S-1/A 1 h35830a3sv1za.htm AMENDMENT NO.3 TO FORM S-1 - REGISTRATION NO.333-134056 sv1za
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As filed with the Securities and Exchange Commission on November 13, 2006
Registration No. 333-134056
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Amendment No. 3
to
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
 
Legacy Reserves LP
(Exact name of registrant as specified in its charter)
         
Delaware   1311   16-1751069
(State or other jurisdiction of
incorporation or organization)		   (Primary Standard Industrial
Classification Code Number)		   (I.R.S. Employer
Identification Number)
303 W. Wall Street, Suite 1600
Midland, Texas 79701
(432) 682-2516
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Steven H. Pruett
President and Chief Financial Officer
Legacy Reserves GP, LLC
303 W. Wall Street, Suite 1600
Midland, Texas 79701
(432) 682-2516
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
Copies to:
Gislar Donnenberg
Andrews Kurth LLP
600 Travis, Suite 4200
Houston, Texas 77002
(713) 220-4200
 
Approximate date of commencement of proposed sale to the public:
From time to time 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.     þ
      If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o
      If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o
      If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o
 
      The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
 
 

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The information in this preliminary prospectus is not complete and may be changed. Securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject To Completion, Dated November 13, 2006
PROSPECTUS
  Legacy Reserves LP
 
  4,209,954 Units
 
  Representing Limited Partner Interests
(LEGACY LOGO)
        This prospectus relates to up to 4,209,954 units, which may be offered for sale by the selling unitholders named in this prospectus. We will not receive any proceeds from the sale of these units. The selling unitholders acquired the units offered by this prospectus in a private equity offering on March 15, 2006.
      The units to which this prospectus relates may be offered and sold from time to time directly from the selling unitholders or alternatively through underwriters or broker-dealers or agents. The units may be sold in one or more transactions, at fixed prices, at prevailing market prices at the time of sale or at negotiated prices. Certain qualified institutional buyers of our units in our private equity offering, have traded our units on the PORTAL® Market. The last trade of our units reported on The PORTAL® Market of which we are aware was reported on October 2, 2006 at a price of $17.25 per unit. Future prices will likely vary from that price and these sales may not be indicative of prices at which our units will be sold. Until our units are regularly traded on The NASDAQ Global Market, we expect that the selling unitholders initially will sell their units at prices between $16.00 per unit and $20.00 per unit, if any units are sold. We intend to apply to list our units on the NASDAQ Global Market under the symbol “LGCY.”
      There has been no public market for our units.
      Investing in our units involves a high degree of risk. See “Risk Factors” beginning on page 23.
      These risks include the following:
  •  We may not have sufficient available cash to pay the full amount of our current quarterly distribution or any distribution at all following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
  •  If we are not able to acquire additional oil and natural gas reserves on economically acceptable terms, our reserves and production will decline, which would adversely affect our business, results of operations and financial condition and our ability to make cash distributions to our unitholders.
 
  •  If commodity prices decline significantly for a prolonged period, we may be forced to reduce our distribution or not be able to pay distributions at all.
 
  •  There is no existing market for our units, and a trading market that will provide our unitholders with adequate liquidity may not develop or be sustained. The price of our units may fluctuate significantly, and our unitholders could lose all or part of their investment.
 
  •  Our Founding Investors, including members of our management, own a 72% limited partner interest in us and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest and limited fiduciary duties, which may permit it to favor its own interests to the detriment of our unitholders.
 
  •  Unitholders have limited voting rights and are not entitled to elect our general partner, and until we have completed an initial public offering or the owners of our general partner own less than 50% of our units, our unitholders will not be entitled to elect any of its directors.
 
  •  Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
 
      Neither the Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved of these securities or determined whether this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
The date of this prospectus is           , 2006.

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(MAP)
(a) Gives pro forma effect to our July 31, 2006 acquisition of 1.46 MMBoe of proved reserves.

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  Amended and Restated Agreement of Limited Partnership of Legacy Reserves LP   A-1
  Glossary of Terms   B-1
  Reserve Reports   C-1
 Consent of BDO Seidman, LLP
 Consent of Johnson, Miller & Co., CPA's PC
 Consent of LaRoche Petroleum Consultants, Ltd.

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SUMMARY
      This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma consolidated financial statements and the notes to those financial statements. You should read “— Legacy Reserves LP — Summary Risk Factors” and “Risk Factors” for information about important factors to consider before buying the units. We include a glossary of some of the terms used in this prospectus in Appendix B. LaRoche Petroleum Consultants, Ltd., an independent engineering firm, provided the estimates of proved oil and natural gas reserves as of December 31, 2005 and June 30, 2006 included in this prospectus. Summaries prepared by LaRoche Petroleum Consultants, Ltd. of its reserve reports as of June 30, 2006 relating to our properties are located at the back of this prospectus as Appendix C and are referred to in this prospectus as the “reserve reports.”
      References in this prospectus to “Legacy Reserves,” “Legacy,” “we,” “our,” “us,” or like terms prior to March 15, 2006 refer to the Moriah Group, Legacy Reserves’ predecessor, including the oil and natural gas properties we acquired in exchange for units and cash from the Moriah Group, the Brothers Group, H2K Holdings, MBN Properties and certain charitable foundations in connection with our private equity offering on March 15, 2006. When used for periods from March 15, 2006 forward, those terms refer to Legacy Reserves LP and its subsidiaries. All references in this prospectus to the number or percentage of units outstanding prior to and after this offering are based upon the 18,451,934 units currently outstanding and do not reflect the up to 6,900,000 units that may be newly issued in Legacy’s proposed initial public offering.
Legacy Reserves LP
      We are an independent oil and natural gas limited partnership, headquartered in Midland, Texas, focused on the acquisition and exploitation of oil and natural gas properties primarily located in the Permian Basin of West Texas and southeast New Mexico. We were formed in October 2005 to own and operate the oil and natural gas properties that we acquired from the Moriah Group, the Brothers Group, H2K Holdings, Ltd. and MBN Properties LP, collectively our “Founding Investors,” and three charitable foundations in connection with the closing of our private equity offering on March 15, 2006. Members of our management team have an average of 22 years of experience in the oil and natural gas industry and over 20 years of experience in the Permian Basin. Our primary business objective is to generate stable cash flows allowing us to make cash distributions to our unitholders and to increase quarterly cash distributions per unit over time through a combination of acquisitions of new and exploitation of our existing oil and natural gas properties.
      We have grown primarily through two activities: the acquisition of producing oil and natural gas properties and the exploitation of proved properties as opposed to the higher risk exploration of unproved properties.
      In June and July 2006, in three separate transactions, we acquired 2.6 MMBoe of proved reserves and related operating rights for an aggregate purchase price of approximately $36.3 million in cash and 146,415 newly issued units. Please see “— Acquisition Activities” below.
      Giving effect to our third quarter acquisition from Kinder Morgan Production Company LP, or Kinder Morgan, our oil and natural gas production and reserve data are as follows:
  •  we had proved reserves of approximately 20.2 MMBoe, of which 72% were oil and 78% were classified as proved developed producing, 4% were proved developed non-producing, and 18% were proved undeveloped as of June 30, 2006;
 
  •  our proved reserves had a standardized measure as of June 30, 2006 of $315.5 million; and
 
  •  our proved reserves to production ratio was approximately 16 years based on the average daily net production for the nine months ended September 30, 2006.
      Our average daily net production was 3,484 Boe/d for the nine months ended September 30, 2006, assuming we had owned all of our current properties as of January 1, 2006.

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      During the period January 1, 2003 through December 31, 2005, we acquired approximately 7.0 MMBoe of proved reserves at a cost of approximately $76.8 million, or $10.95 per Boe of proved reserves. We further increased our proved reserves by approximately 7.0 MMBoe, comprised of revisions of previous estimates due to prices and performance of 3.3 MMBoe; revisions of previous estimates due to infill drilling, recompletions and stimulations of 3.2 MMBoe; and extensions and discoveries of 0.5 MMBoe at a cost of approximately $9.7 million, or $1.39 per Boe. Considering all reserve additions from acquisitions, revisions and extensions, during this period, we added 14.0 MMBoe of proved reserves, investing $86.5 million, for an overall proved reserve replacement cost of $6.17 per Boe.
      Our reserves are located primarily in the Permian Basin, one of the largest and most prolific oil and natural gas producing basins in the United States. The Permian Basin extends over 100,000 square miles in West Texas and southeast New Mexico and has produced over 24 billion Bbls of oil since its discovery in 1921. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. Our producing properties in the Permian Basin are mature fields with established decline curves predominately producing from tight oil reservoirs which are generally not subject to drainage, but are subject to pressure depletion under primary recovery. Approximately 77% of our production for the nine-month period ended September 30, 2006 was from properties under primary recovery, 19% from secondary recovery (waterflood), and 4% from tertiary recovery (CO2 injection). On a proved reserve basis, 76% are primary, 19% are secondary (waterflood), and 5% are tertiary (CO2) projects.
Acquisition Activities
      We have and will continue to focus on identifying, evaluating, executing, integrating and exploiting acquisitions of oil and natural gas properties in the Permian Basin, a large basin characterized by fragmented ownership. During July 2005, there were more than 1,700 operators in the Permian Basin according to the Texas and New Mexico oil and natural gas regulatory commissions, and the top five operators accounted for less than 40% of the total oil production during that period. We believe that our track record and structure will allow us to favorably compete in the acquisition market.
      From January 1, 1999 through July 31, 2006, we invested approximately $146.0 million in 29 acquisitions, which amount excludes $7.0 million allocated to operating rights relating to the South Justis Field acquisition. Based on reserve data prepared at the time of these acquisitions, we added a total of approximately 22.7 MMBoe of proved reserves at a reserve acquisition cost of $6.42 per Boe. These additions include our recent acquisitions described below, and our September 2005 acquisition of approximately 5.6 MMBoe of proved reserves, as evaluated by LaRoche Petroleum Consultants, Ltd. as of September 30, 2005, from PITCO for $63.9 million in cash ($64.3 million, inclusive of asset retirement obligations), representing a proved reserve acquisition cost of $11.49 per Boe.
Recent Acquisitions
      On June 29, 2006, we acquired certain producing properties and related operating rights in the South Justis Field located in Lea County, New Mexico for a purchase price of $13.4 million cash and 146,415 newly issued units. We acquired a 15% operated working interest in the South Justis Unit, a waterflood installed in 1992 that contains 113 producing wells and 97 water injection wells producing approximately 952 gross (125 net) Boe/d for the six months ended June 30, 2006. As of June 30, 2006, total net proved reserves were approximately 0.69 MMBoe, 65% of which are classified as proved developed producing, 21% are proved developed non-producing and 14% are proved undeveloped. We have allocated $8.9 million of the $15.9 million net purchase price to the working interest and reserve acquisition resulting in a proved reserve acquisition cost of $12.88 per Boe, and the balance of $7.0 million was allocated to the related operating rights which entitle us to receive approximately $1.7 million of operating fees annually from third party owners of the properties. We expect to refracture stimulate 38 existing wells and infill drill twelve 20-acre locations over the next three years.
      Also on June 29, 2006, we closed an acquisition of additional operated leases in the Farmer Field located in Crockett and Reagan counties of West Texas, from Larron Oil Corporation, for $5.6 million cash. We

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acquired a 100% operated interest in 50 wells producing 76 net Boe/d and net reserves as of June 30, 2006 of 0.44 MMBoe, all of which are classified as proved developed producing resulting in a proved reserve acquisition cost of $12.73 per Boe. Prior to the Larron acquisition, we operated 111 wells in the Farmer Field.
      On July 31, 2006, we closed the acquisition of properties from Kinder Morgan for approximately $17.3 million cash after closing adjustments. The Kinder Morgan properties contain 85 producing wells and 44 water injection wells located in nine fields in Texas and southeast New Mexico which produce approximately 300 Boe/d net as of July 31, 2006. We operate over 90% of the production. As of July 31, 2006, net proved reserves were 1.46 MMBoe, of which 88% are proved developed producing and 12% are proved undeveloped resulting in a proved reserve acquisition cost of $11.85 per Boe.
      We believe that our recent acquisitions will provide us with continuing opportunities to apply our operational knowledge to increase production and reserves from a variety of known producing formations since many of the acquired properties are near or in the same fields or formations as our other properties. For example, the Kinder Morgan acquisition included production in the Denton Field, which is our largest property in terms of reserve value and the Larron acquisition is adjacent to our existing wells in the Farmer Field, which is our largest property in terms of proved reserves. As a result, we believe these acquisitions will result in operational efficiencies.
Exploitation Activities
      We have also grown reserves and production each year since 1999 through exploitation activities on our existing and acquired properties. Our exploitation activities include accessing additional productive formations in existing wellbores, formation stimulation, artificial lift equipment enhancement, infill drilling on closer well spacing, secondary (waterflood) and tertiary (CO2) recovery projects, drilling for deeper formations and completing unconventional and tight formations. From January 1, 2003 through December 31, 2005, our proved reserves increased by approximately 7.0 MMBoe, comprised of 3.3 MMBoe from revisions of previous estimates due to prices and performance; 3.2 MMBoe from revisions of previous estimates due to infill drilling, recompletions and stimulations; and 0.5 MMBoe through extensions and discoveries. Over the same period our reserve replacement rate, or the ratio of increases in proved reserves to production was 287% excluding acquisitions. Please read “Business — Exploitation Activities” for a discussion of our reserve replacement rate. As of June 30, 2006, we have identified 117 gross (77 net) proved undeveloped drilling locations, 47 gross (10 net) recompletion and formation stimulation projects and one tertiary (CO2) recovery expansion project on our properties, over 90% of which we intend to drill and execute over the next four years. Excluding acquisitions, we expect to make capital expenditures of approximately $10.3 million during the year ending December 31, 2007, including drilling 22 gross (12.9 net) development wells, executing 24 gross (4.1 net) recompletions and refracture stimulations and expanding one tertiary (CO2) recovery project. We currently have rigs operating or committed to drill 100% of our expected development wells for the year ending December 31, 2007.
Hedging Activities
      Our strategy includes hedging a majority of our oil and natural gas production over a three to five-year period. We have hedged approximately 69% of our expected oil and natural gas production from total proved reserves for the year ending December 31, 2007. We have also hedged approximately 61% of our expected oil and natural gas production from total proved reserves for 2008 through 2010. All of our hedges are in the form of fixed price swaps with average annual NYMEX prices of at least $61.51 per Bbl of oil and $7.99 per MMBtu of natural gas. In July 2006, we entered into basis swaps to receive floating NYMEX prices less a fixed basis differential and pay prices based on the floating Waha index, a natural gas hub in West Texas. The prices that we receive for our natural gas sales follow Waha more closely than NYMEX. The basis swaps thereby provide a better match between our natural gas sales and the settlement payments on our natural gas swaps. We have hedged approximately 100% of our NYMEX natural gas basis differential risk on our NYMEX natural gas swaps for 2007 through 2010.

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Business Strategy
      The key elements of our business strategy are to:
  •  make accretive acquisitions of producing properties generally characterized by long-lived reserves with stable production and reserve exploitation potential;
 
  •  grow proved reserves and maximize cash flow and production through exploitation activities and operational efficiencies;
 
  •  focus on the Permian Basin;
 
  •  maintain financial flexibility; and
 
  •  reduce commodity price risk through hedging.
Competitive Strengths
      We believe that we are positioned to successfully execute our business strategy because of the following competitive strengths:
  •  Proven acquisition and exploitation track record.
 
  •  Predictable, long-lived reserve base.
 
  •  Diversified operations and operational control over approximately 70% of our current production.
 
  •  Experienced management team with a vested interest in our success.
Summary of Risk Factors
      An investment in our units involves risks associated with our business, this offering and our limited partnership structure and the tax characteristics of our units. The following list of risk factors is not exhaustive. Please read carefully these and the other risks under the caption “Risk Factors.”
Risks Related to Our Business
  •  We may not have sufficient available cash to pay the full amount of our current quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
  •  If we are not able to acquire additional oil and natural gas reserves on economically acceptable terms, our reserves and production will decline, which would adversely affect our business, results of operations and financial condition and our ability to make cash distributions to our unitholders.
 
  •  Because we distribute all of our available cash to our unitholders, our future growth may be limited.
 
  •  If commodity prices decline significantly for a prolonged period, we may be forced to reduce our distribution or not be able to pay distributions at all.
 
  •  If commodity prices decline significantly for a prolonged period, a significant portion of our exploitation projects may become uneconomic, which may adversely affect our ability to make distributions to our unitholders.
 
  •  Our estimated reserves are based on many assumptions that may prove inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

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  •  Our credit facility has substantial restrictions and financial covenants, and our borrowing base is subject to redetermination by our lenders which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
 
  •  We have a limited operating history as a combined entity and our pro forma operating results may not be indicative of our future operating results.
 
  •  Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the oil and natural gas we produce.
Risks Related to this Offering and Our Limited Partnership Structure
  •  There is no existing market for our units, and a trading market that will provide our unitholders with adequate liquidity may not develop or be sustained. The price of our units may fluctuate significantly, and our unitholders could lose all or part of their investment.
 
  •  Units eligible for future sale may have adverse effects on our unit price and the liquidity of the market for our units.
 
  •  Our Founding Investors, including members of our management, own a 72% limited partner interest in us and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest and limited fiduciary duties, which may permit it to favor its own interests to the detriment of our unitholders.
 
  •  Unitholders have limited voting rights and are not entitled to elect our general partner, and until we have completed an initial public offering or the owners of our general partner own less than 50% of our units, our unitholders will not be entitled to elect any of its directors.
 
  •  Even if unitholders are dissatisfied they cannot remove our general partner without the consent of unitholders owning at least 662/3% of our units, including units owned by our general partner and its affiliates.
 
  •  Our partnership agreement restricts the voting rights of those unitholders owning 20% or more of our units.
 
  •  The owners of our general partner may sell all or part of the general partner to a third party without unitholder consent, which could result in a change of our management or business strategy or both and which would result in an event of default under our revolving credit facility, unless consent of our lenders is obtained.
 
  •  Our Founding Investors and their affiliates (other than our executive officers) may compete directly with us.
 
  •  Cost reimbursements due our general partner and its affiliates will reduce our cash available for distribution to our unitholders.
 
  •  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 a breach of fiduciary duty.
 
  •  Our partnership agreement permits our general partner to redeem any partnership interest held by a limited partner who is a non-citizen assignee.
 
  •  We may issue an unlimited number of additional units without unitholder approval, which would dilute our unitholders’ existing ownership interest in us.

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Tax Risks to Unitholders
  •  Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, will reduce our cash available for distribution to our unitholders.
 
  •  Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
 
  •  A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the costs of any contest will reduce our cash available for distribution to our unitholders.
 
  •  Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.
Principal Executive Offices and Internet Address
      Our principal executive offices are located at 303 W. Wall Street, Suite 1600, Midland, Texas 79701, and our telephone number is (432) 682-2516. Our website is located at http://www.LegacyLP.com. We expect to 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 this prospectus and does not constitute a part of this prospectus.
Formation Transactions
      We are a Delaware limited partnership formed in October 2005 by our Founding Investors to own and operate oil and gas properties and related assets transferred to us by our Founding Investors. Our Founding Investors are:
  •  The Moriah Group — The Moriah Group is comprised of Moriah Properties, Ltd. and DAB Resources, Ltd. Moriah Properties, Ltd. is indirectly owned and controlled by Dale A. Brown, a member of the board of directors of our general partner and Cary D. Brown, the Chief Executive Officer and Chairman of the Board of our general partner. DAB Resources, Ltd. is owned and controlled by Dale A. Brown and Rita Brown.
 
  •  The Brothers Group — The Brothers Group is comprised of Brothers Production Properties, Ltd., Brothers Production Company, Inc., Brothers Operating Company, Inc., and J&W McGraw Properties, Ltd., which entities are directly or indirectly owned and controlled by the McGraw family. Kyle A. McGraw is the Executive Vice President of Business Development and Land and a member of the board of directors of our general partner.
 
  •  MBN Properties LP — The general partner of MBN Properties is MBN Management, LLC with a 1% general partner interest. The Moriah Group, the Brothers Group, H2K Holdings, Ltd. and various private investors (the “Newstone Group”) are the limited partners of MBN Properties.
 
  •  H2K Holdings, Ltd. — H2K Holdings, Ltd. is controlled by Paul T. Horne, our Vice President of Operations.

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      In connection with the closing of our private equity offering on March 15, 2006, we acquired oil and natural gas properties and related assets for aggregate consideration of approximately $73.0 million and issued an aggregate amount of 17,640,068 units as set forth below:
  •  The following entities received units in exchange for contributing to us their respective interests in oil and natural gas producing properties:
                   
        Reserves
        as of
        December 31,
Entity   Units   2005
         
        (MMBoe)
Moriah Properties, Ltd.
     7,334,070       6.08  
DAB Resources, Ltd.
     859,703       0.71  
Brothers Production Properties, Ltd.
     4,968,945       4.02  
Brothers Production Company, Inc.
     264,306       0.21  
Brothers Operating Company, Inc.
     52,861       0.04  
J&W McGraw Properties, Ltd.
     914,246       0.74  
H2K Holdings, Ltd.
     83,499       0.07  
             
 
Total
     14,477,630       11.87  
             
  •  MBN Properties contributed to Legacy Operating Partnership LP 143 oil and natural gas properties and 862 gross producing oil and gas wells located in the Permian Basin that it had acquired from PITCO, an unrelated third party, on September 14, 2005, for a total of 5.42 MMBoe of reserves, as of December 31, 2005, in exchange for $65.3 million cash and 3,162,438 units;
 
  •  We purchased oil and gas properties with an aggregate of 0.65 MMBoe of reserves, as of December 31, 2005, from Charities Support Foundation, Inc., Moriah Foundation, Inc. and the Cary Brown Family Foundation, Inc. for $7.7 million. Two of the foundations, the Moriah Foundation, Inc. and the Cary Brown Family Foundation, were established by Dale A. Brown and Cary D. Brown.
      We received net proceeds of $79.5 million from our private equity offering. With a portion of these proceeds, we redeemed an aggregate of 4,400,000 units for a total consideration of $69.9 million from the following entities, in the following amounts, at a price per unit of $15.81, which is equal to the price per unit received by Legacy from the purchasers in the private equity offering net of initial purchaser’s discount and placement agent’s fee:
                           
            Percentage of
            Currently
            Outstanding
        Units Owned   Units at
            Time of
Entity   Units Redeemed   After Redemption   Redemption
             
Moriah Properties, Ltd.
     1,470,527       5,863,543       31.8%  
DAB Resources, Ltd.
     344,752       514,951       2.8  
Brothers Production Properties, Ltd.
     2,045,133       2,923,812       15.8  
Brother Production Company, Inc.
     108,784       155,522       0.8  
Brothers Operating Company, Inc.
     21,757       31,104       0.2  
J&W McGraw Properties, Ltd.
     376,288       537,958       2.9  
H2K Holdings, Ltd.
     32,759       50,740       0.3  
                   
 
Total
     4,400,000       10,077,630       54.6%  
                   

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Our Organizational Structure
      The following diagram depicts our organizational structure both prior and subsequent to this offering:
(FLOW CHART)
 
(a) The Founding Investors include the Moriah Group, the Brothers Group, MBN Properties LP and H2K Holdings, Ltd. Also includes an aggregate of 73,866 units, representing a 0.3% limited partner interest, comprised of 65,116 restricted units granted to employees and an aggregate of 8,750 units granted to our outside directors.
 
(b) Includes 146,415 units, representing a 0.6% limited partner interest, issued to Henry Holding LP in connection with the June 29, 2006 acquisition of the South Justis properties.

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Our Management
      Our general partner, Legacy Reserves GP, LLC, manages our operations and activities and its board of directors and officers make decisions on our behalf. Certain of the senior officers of our Founding Investors who managed the operations of the assets contributed to us at the closing of our private equity offering on March 15, 2006 continue to manage us. For more information about these individuals, please read “Management — Directors and Executive Officers of Our General Partner.” Our general partner does not receive any management fee or other compensation in connection with the management of our business but it is entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. Our general partner is also entitled to distributions on its approximate 0.1% general partner interest, but is not entitled to receive any distributions (incentive or otherwise) in excess of its approximate 0.1% general partner interest. Please read “Cash Distribution Policy and Restrictions on Distributions,” “Management — Executive Compensation” and “Certain Relationships and Related Transactions.”
      Unlike shareholders in a publicly traded corporation, our unitholders are not entitled to elect our general partner. Prior to an initial public offering resulting in proceeds of not less than $20 million that results in our units being traded on a national securities exchange or the Nasdaq Stock Market, all of the directors of our general partner will be elected by its owners (currently our Founding Investors) and not by our unitholders, except in the following circumstances:
  •  if the owners of our general partner own less than 50% but at least 35% of our units, the unitholders, including the general partner and its affiliates, will be entitled to elect three of the seven directors;
 
  •  if the owners of our general partner own less than 35% but at least 20% of our units, the unitholders, including the general partner and its affiliates, will be entitled to elect five of the seven directors; and
 
  •  if the owners of our general partner own less than 20% of our units, the unitholders, including the general partner and its affiliates, will be entitled to elect all of the directors.
Following an initial public offering resulting in proceeds of not less than $20 million that results in our units being traded on a national securities exchange or the Nasdaq Stock Market, our unitholders, including the general partner and its affiliates, will be entitled to elect all of the directors of our general partner. Please read “The Partnership Agreement — Meetings; Voting.”

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The Offering
Units offered by selling unitholders 4,209,954 units. Simultaneously with this offering we are registering the offer and sale of up to 790,046 units held by Friedman, Billings, Ramsey Group, Inc. and its affiliates in a separate registration statement. The selling unitholders will be unable to sell the units offered hereby until the expiration of a 75 day lock-up period following the effective date of the registration statement filed on November 13, 2006 to register the offer and sale of up to 6,900,000 newly issued units in an underwritten initial public offering.
 
Units outstanding prior to and after this offering 18,451,934 units. On November 13, 2006 we filed an additional registration statement to register the offer and sale of up to 6,900,000 newly issued units in an underwritten initial public offering. As a result, prior to and after this offering there may be 24,451,934 units outstanding (25,351,934 if the underwriters’ option to purchase additional units in connection with the initial public offering is exercised in full).
 
Use of proceeds We will not receive any proceeds from the sale of units by the selling unitholders.
 
Cash distributions We will distribute all of our cash on hand at the end of each quarter, after payment of fees and expenses, less reserves (including reserves for capital expenditures) established by our general partner in its discretion. Unlike most publicly traded partnerships, we will not pay incentive distributions to our general partner. In general, we will distribute 99.9% of our available cash each quarter to our unitholders and approximately 0.1% of our available cash to our general partner. We refer to this cash as “available cash,” and we define its meaning in more detail in our partnership agreement and in the glossary of terms found in Appendix B. Our general partner has broad discretion in establishing reserves for the proper conduct of our business. These reserves, which could be substantial, will reduce the amount of cash available for distribution to our unitholders.
 
We intend to make our current quarterly distribution of $0.41 per unit, or $1.64 per unit on an annualized basis, to the extent we have sufficient available cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner in reimbursement for expenses incurred by it on our behalf. The amount of available cash, if any, at the end of any quarter may be greater than or less than the aggregate amount of our current quarterly distribution to be distributed on all units.
 
We believe, based on the assumptions and considerations included in “Cash Distribution Policy and Restrictions on Distribution — Assumptions and Considerations,” that we will generate sufficient cash flow from operations to enable us to pay the full amount of our current quarterly distribution of $0.41 on all units for each quarter through December 31, 2007.

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On August 14, 2006, we paid a pro-rated distribution for the period beginning on March 15, 2006 and ending on March 31, 2006 concurrently with the distribution attributable to the second quarter of 2006 in the aggregate amount of $0.4874 per unit, which is based on our quarterly distribution rate of $0.41 per unit. On November 14, 2006 we will pay unitholders who were of record as of October 31, 2006 a distribution of $0.41 per unit attributable to the third quarter of 2006. However, we cannot assure you that any additional distributions will be declared or paid.
 
If we had completed our private equity offering and the related formation transactions and our June and July 2006 acquisitions of our properties, on January 1, 2005, pro forma cash available to pay distributions during the year ended December 31, 2005 would have been approximately $28.1 million. We estimate that our pro forma available cash for the year ended December 31, 2005 would have been sufficient to pay approximately 93% of the current quarterly distributions on our units during this period. However, our pro forma cash available to pay distributions for the twelve months ended September 30, 2006 would have been sufficient to pay the full annualized distribution. For a calculation of our ability to make distributions to you based on our pro forma results please read “Cash Distribution Policy and Restrictions on Distributions.”
 
Issuance of additional units We can issue an unlimited number of additional units without the consent of our unitholders. On November 13, 2006 we filed an additional registration statement to register the offer and sale of up to 6,900,000 newly issued units in an underwritten initial public offering.
 
Agreement to be bound by limited partnership agreement; voting rights By purchasing a unit, you will be admitted as a limited partner of our partnership and will be deemed to have agreed to be bound by all of the terms of our partnership agreement. Our general partner manages and operates us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will not have the right to elect our general partner. And our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. The Founding Investors, who are also the owners of our general partner, including members of our management, own an aggregate of 72% of our units. This gives the Founding Investors the ability to determine the outcome of substantially all unitholder votes, including the ability to block our general partner’s removal.
 
Prior to an initial public offering resulting in proceeds of not less than $20 million that results in our units being traded on a national securities exchange or the Nasdaq Stock Market, all of the directors of our general partner will be elected by its owners

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(currently our Founding Investors) and not by our unitholders, except in the following circumstances:
 
• if the owners of our general partner own less than 50% but at least 35% of our units, the unitholders, including the general partner and its affiliates, will be entitled to elect three of the seven directors;
 
• if the owners of our general partner own less than 35% but at least 20% of our units the unitholders, including the general partner and its affiliates, will be entitled to elect five of the seven directors; and
 
• if the owners of our general partner own less than 20% of our units the unitholders, including the general partner and its affiliates, will be entitled to elect all of the directors.
 
Following an initial public offering resulting in proceeds of not less than $20 million that results in our units being traded on a national securities exchange or the Nasdaq Stock Market, our unitholders, including the general partner and its affiliates, will be entitled to elect all of the directors of our general partner. Please read “The Partnership Agreement — Meetings; Voting.”
 
Limited call right If at any time our general partner and its affiliates own more than 85% of our outstanding units, our general partner has the right, but not the obligation, to purchase all of the remaining units at a price not less than the then-current market price of the units.
 
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.”
 
Exchange Listing We intend to apply to list our units on the NASDAQ Global Market under the symbol “LGCY.”
 
Absence of Public Market There is no public market for our units and no public market will exist upon the completion of this offering.

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Summary Historical and Pro Forma
Consolidated Financial and Operating Data
      We were formed in October 2005. Upon completion of our private equity offering and as a result of the related formation transactions on March 15, 2006, we acquired oil and natural gas properties and business operations from the Founding Investors and three charitable foundations. Although we were the acquiring entity for legal purposes, the formation transactions were treated as a purchase with Moriah Properties, Ltd. and its affiliates, or the Moriah Group, being considered, on a combined basis, as the acquiring entity for accounting purposes. As a result, Legacy Reserves LP (formerly the Moriah Group) applied the purchase method of accounting to the assets and the liabilities of the oil and natural gas properties acquired from the Founding Investors (other than the Moriah Group) and the charitable foundations. Our financial statements for periods prior to March 15, 2006 only reflect the accounts of the Moriah Group.
      The following table shows summary historical and pro forma financial and operating data for Legacy Reserves LP for the periods and as of the dates indicated. Through March 15, 2006, Legacy’s accompanying consolidated historical financial statements reflect the accounts of the Moriah Group, which includes the accounts of Moriah Resources, Inc., the general partner of Moriah Properties, Ltd., Moriah Properties, Ltd., the oil and natural gas interests individually owned by Dale A. and Rita Brown until October 1, 2005, when those interests were transferred to DAB Resources, Ltd., and the accounts of MBN Properties LP. The Moriah Group consolidated MBN Properties LP as a variable interest entity with the portion of net income (loss) applicable to the other owners’ equity interests being eliminated through a non-controlling interest adjustment. Although MBN Management, LLC, the general partner of MBN Properties LP, is also a variable interest entity, it was accounted for by the Moriah Group using the equity method. From March 15, 2006 Legacy’s historical financial statements include the results of operations of the oil and natural gas properties acquired from the Founding Investors (other than the Moriah Group) and the charitable foundations.
      The summary historical financial data of Legacy for the years ended December 31, 2003, 2004 and 2005 are derived from the audited consolidated financial statements of Legacy included elsewhere in this prospectus. Since the PITCO properties were not acquired by MBN Properties LP until September 14, 2005, the consolidated results of operations for Legacy for the year ended December 31, 2005 only include the operating results for the PITCO properties for the period of September 14, 2005 through December 31, 2005.
      The unaudited summary pro forma financial data of Legacy is derived from the unaudited pro forma financial statements of Legacy included elsewhere in this prospectus. The pro forma statements of operations give pro forma effect to (i) the formation of MBN Properties LP and its acquisition of properties from PITCO, (ii) the private equity offering and the related formation transactions, (iii) the acquisition of the South Justis Unit properties from Henry Holding LP and (iv) the acquisition of properties from Kinder Morgan. The pro forma statements of operations do not give pro forma effect to the Farmer Field acquisition. The pro forma adjustments have been prepared as if the transactions had taken place as of January 1, 2005, in the case of the pro forma statements of operations for the year ended December 31, 2005 and the nine months ended September 30, 2006. The unaudited summary pro forma financial data are not necessarily indicative of operating results or the financial position that would have been achieved had the events described above been completed on those dates and are not necessarily indicative of future operating results.
      You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Legacy’s financial statements and related notes included elsewhere in this prospectus. You should also read the pro forma information together with the unaudited pro forma financial statements of Legacy Reserves LP and related notes included elsewhere in this prospectus.

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      The following table presents the non-GAAP financial measures which we are required to report to our lenders in order to satisfy financial covenants under our revolving credit facility, Adjusted EBITDA, Ratio of Adjusted EBITDA to interest expense and Adjusted current ratio. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities — Our Revolving Credit Facility.” These measures are not calculated or presented in accordance with generally accepted accounting principles, or GAAP. These measures are presented because such information is relevant and is used to assess compliance with our loan covenants. Adjusted EBITDA is also used as a supplemental performance measure by our management and by external users of our financial statements to assess the financial performance, operating performance and return of capital of our assets as compared to other companies in the exploration and production industry without regard to financing methods, capital structure or historical cost basis. We explain these measures below and reconcile them to the most directly comparable financial measures calculated and presented in accordance with GAAP in “— Non-GAAP Financial Measures” beginning on page 21.
                                                             
    Historical   Pro Forma
         
        Nine Months Ended       Nine Months
    Year Ended December 31,   September 30,   Year Ended   Ended
            December 31,   September 30,
    2003   2004   2005(a)   2005(a)   2006(b)   2005(c)   2006(c)
                             
                (Unaudited)   (Unaudited)
    (In thousands)
Statement of Operations Data:
                                                        
Revenues:
                                                        
 
Oil sales
   $ 7,919     $ 10,998     $ 18,225     $ 11,419     $ 32,444     $ 46,357     $ 40,461  
 
Natural gas sales
     3,697       3,945       7,318       3,872       10,822       16,167       12,006  
 
Realized and unrealized gain (loss) on oil and natural gas swaps
     (283 )     (633 )     (6,159 )     (7,649 )     5,534       (11,048 )     4,229  
                                           
   
Total revenues
     11,333       14,310       19,384       7,642       48,800       51,476       56,696  
                                           
Expenses:
                                                        
 
Oil and natural gas production
     3,496       4,345       6,376       3,610       10,160       14,637       12,530  
 
Production and other taxes
     661       928       1,636       1,140       2,710       4,152       3,421  
 
General and administrative
     543       731       1,354       439       3,265       3,056       3,769  
 
Dry hole costs
     1,465       1       —       —       —       206       —  
 
Depletion, depreciation, amortization and accretion
     766       883       2,291       736       12,702       18,063       15,912  
 
Impairment of long-lived assets
     471       —       —       —       8,573       6       8,572  
 
(Gain) loss on sale of assets
     —       —       20       —       —       (299 )     —  
                                           
   
Total expenses
     7,402       6,888       11,677       5,925       37,410       39,821       44,204  
                                           
 
Operating income
     3,931       7,422       7,707       1,717       11,390       11,655       12,492  

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    Historical   Pro Forma
         
        Nine Months Ended       Nine Months
    Year Ended December 31,   September 30,   Year Ended   Ended
            December 31,   September 30,
    2003   2004   2005(a)   2005(a)   2006(b)   2005(c)   2006(c)
                             
                (Unaudited)   (Unaudited)
    (In thousands)
Other income (expense):
                                                        
 
Interest income
     56       419       185       153       94       639       94  
 
Interest expense
     (94 )     (213 )     (1,584 )     (293 )     (4,512 )     (6,928 )     (5,732 )
 
Gain on sale of partnership investment
     —       1,292       —       —       —       —       —  
 
Equity in income (loss) of partnerships
     311       183       (495 )     (338 )     (318 )     —       21  
 
Other
     3       92       45       45       15       141          
                                           
   
Income before non-controlling interest
     4,207       9,195       5,858       1,284       6,669       5,507       6,875  
 
Non-controlling interest
     —       —       1       1       —       —       —  
                                           
   
Income from continuing operations
     4,207       9,195       5,859     $ 1,285     $ 6,669     $ 5,507     $ 6,875  
                                           
 
Discontinued operations:
                                                        
   
Income from operations
     10       15       —       —       —                  
   
Gain on disposal
     233       7       —       —       —                  
                                           
 
Income from discontinued operations
     243       22       —       —       —                  
                                           
 
Cumulative effect of accounting change
     (223 )     —       —       —       —                  
                                           
 
Net Income
   $ 4,227     $ 9,217     $ 5,859     $ 1,285     $ 6,669                  
                                           
Earnings per unit from continuing operations:
                                                        
 
Basic and fully diluted
   $ 0.44     $ 0.97     $ 0.62       0.14       0.42     $ 0.30     $ 0.37  
                                           
Cash Flow Data:
                                                        
 
Net cash provided by operating activities
   $ 6,799     $ 8,586     $ 14,409     $ 10,124     $ 21,818                  
 
Net cash provided by (used in) investing activities
   $ (8,475 )   $ 1,023     $ (68,965 )   $ (70,076 )   $ (53,827 )                
 
Net cash provided by (used in) financing activities
   $ 1,717     $ (8,958 )   $ 55,742     $ 60,894     $ 31,698                  
 
Capital expenditures
   $ 4,047     $ 3,325     $ 66,915     $ 65,498     $ 45,553                  
Other Financial Information (unaudited):
                                                        
 
Adjusted EBITDA(d)
   $ 4,907     $ 9,397     $ 12,877     $ 6,770       25,059     $ 34,232     $ 31,145  
 
Ratio of Adjusted EBITDA to Interest Expense(e)
     52.2x       44.1x       8.1x       23.1x       5.6x       4.9x       5.4x  
 
(a)  Reflects MBN Properties LP’s purchase of the PITCO properties on September 14, 2005. Consequently, the operations of the PITCO properties are only included for the period of September 14, 2005 through December 31, 2005.

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(b)  Reflects Legacy’s purchase of the oil and natural gas properties acquired in the March 15, 2006 formation transactions and the South Justis, Farmer Field and Kinder Morgan acquisitions. Consequently, the operations of these acquired properties are only included for the period from the closing dates of such acquisitions through September 30, 2006.
(c)  Do not reflect the Farmer Field acquisition.
(d)  Please read “— Non-GAAP Financial Measure” beginning on page 21.
(e)  Our revolving credit facility requires us to maintain consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0.
                                     
    Historical
     
    As of December 31,   As of
        September 30,
    2003   2004   2005   2006
                 
                (Unaudited)
    (In thousands)
Balance Sheet Data:
                                
 
Cash and cash equivalents
   $ 117     $ 769     $ 1,955     $ 1,644  
 
Other current assets
     7,826       5,799       6,316       14,413  
 
Oil and natural gas properties, net of accumulated depletion, depreciation, and amortization
     9,954       12,224       77,172       249,049  
 
Other assets
     651       —       1,499       7,736  
                         
   
Total assets
   $ 18,548     $ 18,792     $ 86,942     $ 272,842  
                         
 
Current liabilities
   $ 9,157     $ 4,898     $ 4,562     $ 8,669  
 
Long-term debt
     —       —       52,473       106,800  
 
Other long-term liabilities
     2,113       1,872       19,998       7,815  
 
Owners’ equity
     7,278       12,022       9,909       149,558  
                         
   
Total liabilities and owners’ equity
   $ 18,548     $ 18,792     $ 86,942     $ 272,842  
                         

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Summary Reserve and Operating Data
      The following table sets forth a summary of information related to our net proved reserves as of the dates indicated, including:
  •  the historical reserves of the Moriah Group as of December 31, 2003, 2004 and 2005;
 
  •  our combined reserves as of December 31, 2005, giving effect to our acquisition of the oil and natural gas properties from the Founding Investors and charitable foundations on March 15, 2006; we refer to this presentation of reserves as our “combined for initial formation transactions” reserves in this prospectus; and
 
  •  our combined reserves as of December 31, 2005 and June 30, 2006, giving effect to our acquisition of the oil and natural gas properties from the Founding Investors and charitable foundations on March 15, 2006 as well as our South Justis, Farmer Field and Kinder Morgan acquisitions completed in June and July 2006; we refer to this presentation of reserves as our “consolidated combined” reserves in this prospectus.
      Estimates of our historical and combined net proved reserves as of December 31, 2003, 2004 and 2005 and June 30, 2006 are based on reserve reports prepared by LaRoche Petroleum Consultants, Ltd., an independent petroleum engineering firm. Summaries of the June 30, 2006 reserve reports are attached to this prospectus as Appendix C. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business — Oil and Natural Gas Data — Proved Reserves” and the summaries of reserve reports included in this prospectus in evaluating the information presented below.
                                                       
                Combined        
                for Initial    
        Formation   Consolidated
    Historical   Transactions   Combined
             
    As of December 31,   As of   As of   As of
        December 31,   December 31,   June 30,
    2003   2004   2005(a)   2005   2005   2006
                         
Reserve Data:
                                                
 
Estimated net proved reserves:
                                                
   
Oil (MMBbls)
     3.3       4.1       8.1       12.3       14.1       14.5  
   
Natural gas (Bcf)
     10.3       10.5       24.5       33.8       35.4       33.9  
                                     
     
Total (MMBoe)
     5.0       5.9       12.2       17.9       20.0       20.2  
 
Proved developed reserves (MMBoe)
     5.0       5.9       9.8       14.9       16.8       16.5  
 
Proved undeveloped reserves (MMBoe)
     —       —       2.4       3.0       3.2       3.7  
 
Proved developed reserves as a percentage of total proved reserves
     100 %     100 %     80 %     83 %     84 %     82 %
 
Standardized measure (in millions)(b)
   $ 41.4     $ 60.4     $ 192.2     $ 277.2     $ 307.8     $ 315.5 (c)
Oil and Natural Gas Prices(d):
                                                
 
Oil — NYMEX WTI per Bbl
   $ 32.52     $ 43.45     $ 61.05     $ 61.05     $ 61.05     $ 73.92  
 
Natural gas — NYMEX Henry Hub per MMBtu
   $ 6.19     $ 6.15     $ 11.25     $ 11.25     $ 11.25     $ 6.06  
 
(a)  Includes 3.2 MMBbls of oil, 13.0 Bcf of natural gas and $93.3 million of standardized measure held by MBN Properties LP of which 1.7 MMBbls of oil, 7.0 Bcf of natural gas and $50.2 million of standardized measure is owned by the non-controlling interest.

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(b)  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 (using prices and costs in effect as of the period end date) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depletion, depreciation and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. Standardized measure does not give effect to derivative transactions, such as commodity swaps. The standardized measure is based on the period end date NYMEX prices shown for oil and natural gas as of such date, with these index prices adjusted as appropriate to wellhead prices based on historical price differentials. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operations.”
(c)  The standardized measure as of September 30, 2006 was $243.8 million based on an internal reserve report using NYMEX oil and natural gas prices of $62.91 per barrel and $5.62 per MMBtu, respectively, as of market close on September 29, 2006, the last trading day of the third quarter, with these representative prices adjusted by field to arrive at the appropriate net price.
(d)  Oil and natural gas prices as of each date are based on NYMEX prices per Bbl of oil and per MMBtu of natural gas as of the last trading day of the period for the near month contract, with these representative prices adjusted by field to arrive at the appropriate net price.
      The following table sets forth a summary of unaudited information with respect to our production and sales of oil and natural gas for the periods indicated, including:
  •  the historical production and sales of oil and natural gas data of the Moriah Group as of December 31, 2003, 2004 and 2005 and for the nine months ended September 30, 2006 reflects Legacy’s purchase of the oil and natural gas properties acquired in the March 15, 2006 formation transactions and the South Justis, Farmer Field and Kinder Morgan acquisitions;
 
  •  our combined production and sales of oil and natural gas data for the year ended December 31, 2005, giving effect to our acquisition of the oil and natural gas properties from the Founding Investors and charitable foundations on March 15, 2006 as if it had occurred on January 1, 2005; we refer to this presentation of production and sales of oil and natural gas data as our “combined for initial formation transactions” production in this prospectus; and
 
  •  our combined production and sales of oil and natural gas data for the year ended December 31, 2005 and the nine months ended September 30, 2006, giving effect to our acquisition of the oil and natural gas properties from the Founding Investors and charitable foundations on March 15, 2006 as well as our South Justis, Farmer Field and Kinder Morgan acquisitions completed in June and July 2006 as if they had occurred on January 1, 2005; we refer to this presentation of production and sales of oil and natural gas data as our “consolidated combined” production in this prospectus.

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      The following table excludes production and sales of oil and natural gas relating to discontinued operations. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business — Oil and Natural Gas Data — Production and Price History” and the summaries of reserve reports included in this prospectus in evaluating the information presented below.
                                                             
        Combined   Consolidated
    Historical   for Initial   Combined
        Formation    
        Nine Months   Transactions       Nine Months
    Year Ended December 31,   Ended   Year Ended   Year Ended   Ended
        September 30,   December 31,   December 31,   September 30,
    2003   2004   2005(a)   2006(b)   2005   2005   2006
                             
Net Production:
                                                        
 
Oil (MBbls)
     279       286       354       516       748       922       648  
 
Natural gas (MMcf)
     848       783       1,027       1,599       2,282       2,472       1,815  
   
Total (MBoe)
     420       416       525       782       1,128       1,334       951  
   
Average daily (Boe/d)
     1,152       1,138       1,438       2,864       3,090       3,655       3,484  
Average Sales Prices (including hedges)(c):
                                                        
 
Oil (per Bbl)
   $ 28.40     $ 36.24     $ 38.94 (d)   $ 52.11 (e)   $ 38.42 (f)   $ 41.34 (f)   $ 50.28 (e)
 
Natural gas (per Mcf)
   $ 4.02     $ 5.04     $ 5.45     $ 13.70     $ 6.06     $ 6.05     $ 13.76  
 
Combined (per Boe)
   $ 26.98     $ 34.40     $ 36.92 (d)   $ 62.40 (e)   $ 37.73 (f)   $ 39.79 (f)   $ 60.56 (e)
Average Sales Prices (including realized hedge gains/losses)(g):
                                                        
 
Oil (per Bbl)
   $ 26.79     $ 38.61     $ 41.51 (d)   $ 49.51 (e)   $ 41.68 (f)   $ 43.96 (f)   $ 52.57 (e)
 
Natural gas (per Mcf)
   $ 4.15     $ 4.89     $ 7.13     $ 9.72     $ 6.76     $ 6.76     $ 9.67  
 
Combined (per Boe)
   $ 26.17     $ 35.74     $ 41.93 (d)   $ 52.54 (e)   $ 41.31 (f)   $ 42.80 (f)   $ 54.30 (e)
Average Sales Prices (excluding hedges):
                                                        
 
Oil (per Bbl)
   $ 28.38     $ 38.45     $ 51.48     $ 62.88     $ 51.08     $ 51.59     $ 63.41  
 
Natural gas (per Mcf)
   $ 4.36     $ 5.04     $ 7.13     $ 6.77     $ 6.76     $ 6.70     $ 6.74  
 
Combined (per Boe)
   $ 27.66     $ 35.92     $ 48.65     $ 55.33     $ 47.53     $ 48.07     $ 56.11  
Average Unit Costs Per Boe:
                                                        
 
Oil and natural gas production expenses
   $ 8.32     $ 10.44     $ 12.14     $ 12.99     $ 10.67     $ 11.21     $ 13.32  
 
Production taxes
   $ 1.57     $ 2.23     $ 3.12     $ 3.47     $ 3.06     $ 3.18     $ 3.65  
 
General and administrative expenses
   $ 1.29     $ 1.76     $ 2.58     $ 4.18     $ 3.43     $ 2.29     $ 3.96  
 
Depletion, depreciation, amortization and accretion
   $ 1.82     $ 2.12     $ 4.36     $ 16.24     $ 13.38     $ 13.84     $ 16.95  
 
(a)  Reflects MBN Properties LP’s purchase of PITCO properties on September 14, 2005. Consequently, the operations of the PITCO properties are only included for the period following the date of acquisition.
(b)  Reflects Legacy’s purchase of the oil and natural gas properties acquired in the March 15, 2006 formation transactions and the South Justis, Farmer Field and Kinder Morgan acquisitions. Consequently, the operations of these acquired properties are only included for the period from the closing dates of such acquisitions through September 30, 2006.
(c)  Includes both the realized and unrealized hedge gains and losses from Legacy’s oil and natural gas swaps. Since Legacy does not specifically designate its commodity derivative instruments as cash flow hedges, current earnings reflect a mark-to-market adjustment for these instruments. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods. See Note 10 on page F-35 for details regarding Legacy’s unrealized gains and losses.

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(d)  Includes the effects of approximately $2.0 million of derivative premiums for the year ended December 31, 2005 to cancel and reset 2006 oil swaps from $51.31 to $59.38 per Bbl and approximately $0.8 million of premiums paid on July 22, 2005 for an option to enter into a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised.
(e)  Includes the effect of approximately $4.0 million of derivative premiums for the nine month period ending September 30, 2006 to cancel and reset 2007 oil swaps from $60.00 to $65.82 per barrel for 372,000 barrels and for 2008 oil swaps from $60.50 to $66.44 per barrel for 348,000 barrels, which reflected the prevailing oil swap market at the time of the reset.
(f)  Includes the effects of approximately $3.5 million of derivative premiums for the year ended December 31, 2005 to cancel and reset 2006 oil swaps from $51.31 to $59.38 per Bbl and approximately $0.8 million of premiums paid on July 22, 2005 for an option to enter into a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised.
(g)  Includes only the realized hedge gains (losses) from Legacy’s oil and natural gas swaps.

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Non-GAAP Financial Measures
Adjusted EBITDA
      Adjusted EBITDA is a financial measurement that we report to our lenders and use as a gauge for compliance with our EBITDA-to-interest covenant in our revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities — Our Revolving Credit Facility.”
      Adjusted EBITDA is defined in our revolving credit facility as net income (loss) plus:
  •  Interest expense;
 
  •  Depletion, depreciation, amortization and accretion;
 
  •  Impairment of long-lived assets;
 
  •  (Gain) loss on sale of partnership investment;
 
  •  (Gain) loss on sale of assets;
 
  •  Equity in (income) loss of partnerships; and
 
  •  Unrealized (gain) loss on oil and natural gas swaps.
      Adjusted EBITDA is also used as a supplemental performance measure by our management and by external users of our financial statements such as industry analysts, investors, lenders, rating agencies and others to assess:
  •  the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
 
  •  our operating performance and return on capital as compared to those of other companies in the exploration and production industry, without regard to financing or capital structure.
      Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
     Adjusted Current Ratio
      Adjusted current ratio is a financial measure that we report to our lenders and use as a gauge for compliance with our current ratio covenant in our revolving credit facility. We are required to maintain a ratio of consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under SFAS No. 133, which includes the current portion of oil, natural gas and interest rate swaps. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities — Our Revolving Credit Facility.”

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      The following table presents a reconciliation of our net income to Adjusted EBITDA, the Adjusted EBITDA to interest expense ratio and calculation of our Adjusted current ratio:
                                                           
    Historical        
             
        Nine Months   Pro Forma
        Ended    
    Year Ended December 31,   September 30,   Year Ended   Nine Months
            December 31,   Ended
    2003   2004   2005   2005   2006   2005   September 30, 2006
                             
    (In thousands)
Net income
   $ 4,227     $ 9,217     $ 5,859     $ 1,285     $ 6,669     $ 5,507     $ 6,875  
Plus:
                                                        
 
Interest expense
     94       213       1,584       293       4,512       6,928       5,732  
 
Depletion, depreciation, amortization and accretion
     766       883       2,291       736       12,702       18,063       15,912  
 
Impairment of long-lived assets
     471       —       —       —       8,573       6       8,573  
 
(Gain) loss on sale of assets
     —       —       20       —       —       (299 )     —  
 
(Gain) on sale of partnership investment
     —       (1,292 )     —       —       —       —       —  
 
Equity in (income) loss of partnerships
     (311 )     (183 )     495       338       318       —       —  
 
Unrealized (gain) loss on oil and natural gas swaps
     (340 )     559       2,628       4,118       (7,715 )     4,027       (5,947 )
                                           
 
Adjusted EBITDA
   $ 4,907     $ 9,397     $ 12,877     $ 6,770     $ 25,059     $ 34,232     $ 31,145  
                                           
 
Interest expense
   $ 94     $ 213     $ 1,584     $ 293     $ 4,512     $ 6,928     $ 5,732  
 
Adjusted EBITDA to interest expense ratio
     52.2x       44.1x       8.1x       23.1x       5.6x       4.9x       5.4x  

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RISK FACTORS
      Limited partner interests are inherently different from 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 similar business. Our unitholders should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our units.
      The following risks could materially and adversely affect our business, financial condition or results of operations. If any of the events described below were to occur, we might not be able to pay the full amount of our current quarterly distribution on our units, the trading price of our units could decline and our unitholders could lose all or part of their investment.
Risks Related to Our Business
  We may not have sufficient available cash to pay the full amount of our current quarterly distribution or any distribution at all following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
      We may not have sufficient available cash each quarter to pay the full amount of our current quarterly distribution or any distribution at all. The amount of cash we distribute in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than our current quarterly distribution of $0.41 per unit. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserves that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. Further, our debt agreements contain restrictions on our ability to pay distributions. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
  •  the amount of oil and natural gas we produce;
 
  •  the price at which we are able to sell our oil and natural gas production;
 
  •  whether we are able to acquire additional oil and natural gas properties at economically attractive prices;
 
  •  whether we are able to continue our exploitation activities at economically attractive costs;
 
  •  the level of our operating costs, including payments to our general partner;
 
  •  the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon; and
 
  •  the level of our capital expenditures.
If we are not able to acquire additional oil and natural gas reserves on economically acceptable terms, our reserves and production will decline, which would adversely affect our business, results of operations and financial condition and our ability to make cash distributions to our unitholders.
      If we are unable to develop our proved undeveloped reserves and our wells do not produce as expected, our reserves may decline more rapidly than we have estimated. Our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

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Because we distribute all of our available cash to our unitholders, our future growth may be limited.
      Since we will distribute all of our available cash as defined in our partnership agreement to our unitholders, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. We will depend on financing provided by commercial banks and other lenders and the issuance of debt and equity securities to finance any significant growth or acquisitions. If we are unable to obtain adequate financing from these sources, our ability to grow will be limited.
If commodity prices decline significantly for a prolonged period, we may be forced to reduce our distribution or not be able to pay distributions at all.
      A significant decline in oil and natural gas prices over a prolonged period would have a significant impact on the value of our reserves and on our cash flow, which would force us to reduce or suspend our distribution. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
  •  the domestic and foreign supply of and demand for oil and natural gas;
 
  •  the price and quantity of imports of crude oil and natural gas;
 
  •  overall domestic and global economic conditions;
 
  •  political and economic conditions in other oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
 
  •  the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
 
  •  the level of consumer product demand;
 
  •  weather conditions;
 
  •  the impact of the U.S. dollar exchange rates on oil and natural gas prices; and
 
  •  the price and availability of alternative fuels.
      In the past, the prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2005, the NYMEX monthly oil index price ranged from a high of $65.55 per Bbl to a low of $46.85 per Bbl and the NYMEX gas index price (last day) ranged from a high of $13.91 per MMbtu to a low of $6.12 per MMBtu.
If commodity prices decline significantly for a prolonged period, a significant portion of our exploitation projects may become uneconomic, which may adversely affect our ability to make distributions to our unitholders.
      Lower oil and natural gas prices may not only decrease our revenues, but also reduce the amount of oil and natural gas that we can produce economically. Furthermore, substantial decreases in oil and natural gas prices as were experienced as recently as 2002, when prices of less than $20.00 per Bbl of oil and $2.00 per Mcf of natural gas were received at the wellhead in the Permian Basin, would render a significant portion of our exploitation projects uneconomic. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility to pay distributions to our unitholders.

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Our estimated reserves are based on many assumptions that may prove inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
      No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. 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.
Our credit facility has substantial restrictions and financial covenants, and our borrowing base is subject to redetermination by our lenders which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
      We will depend on our revolving credit facility for future capital needs. Our revolving credit facility restricts, among other things, our ability to incur debt and pay distributions, and requires us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under our revolving credit facility could result in a default under our revolving credit facility. A default under our revolving credit facility could cause all of our existing indebtedness to be immediately due and payable. Additionally, our revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion.
      We are prohibited from borrowing under our revolving credit facility to pay distributions to unitholders if the amount of borrowings outstanding under our revolving credit facility reaches or exceeds 90% of the borrowing base, which is the amount of money available for borrowing, as determined semi-annually by our lenders in their sole discretion. The lenders will redetermine the borrowing base based on an engineering report with respect to our oil and natural gas reserves, which will take into account the prevailing oil and natural gas prices at such time. Any time our borrowings exceed 90% of the then specified borrowing base, our ability to pay distributions to our unitholders in any such quarter is solely dependent on our ability to generate sufficient cash from our operations. Our borrowings under our credit facility as of September 30, 2006 are approximately $106.8 million, or 82% of our borrowing base of $130 million.
      Outstanding borrowings in excess of the borrowing base must be repaid, and, if mortgaged properties represent less than 80% of total value of oil and gas properties used to determine the borrowing base, we must pledge other oil and natural gas properties as additional collateral. We may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility.
      The occurrence of an event of default or a negative redetermination of our borrowing base could adversely affect our business, results of operations, financial condition and our ability to make distributions to our unitholders. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities.”
We have a limited operating history as a combined entity and our pro forma operating results may not be indicative of our future operating results.
      As a combined entity, we conducted no operations and generated no revenues until March 15, 2006 when we acquired oil and natural gas properties from our Founding Investors and the charitable foundations simultaneously with the closing of our private equity offering, including the PITCO properties, which our management team has operated only since September 2005.

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      Our pro forma combined financial results cover periods during which the oil and natural gas properties that we acquired were not under common control and therefore may not be indicative of our future financial or operating results.
Our business depends on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market the oil and natural gas we produce.
      The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems 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 to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Our exploitation projects require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.
      We make and expect to continue to make substantial capital expenditures in our business for the exploitation, development, production and acquisition of oil and natural gas reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:
  •  our proved reserves;
 
  •  the level of oil and natural gas we are able to produce from existing wells;
 
  •  the prices at which our oil and natural gas are sold; and
 
  •  our ability to acquire, locate and produce new reserves.
      If our revenues or the borrowing base under our credit facility decrease as a result of lower oil and/or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility restricts our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
We do not control all of our operations and exploitation projects and failure of an operator of wells in which we own partial interests to adequately perform could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
      Much of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas wells. We currently operate approximately 70% of our production.

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      If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The success and timing of our exploitation activities on properties operated by others is outside of our control.
      The failure of an operator of wells in which we own partial interests to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our production and revenues and could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Shortages of drilling rigs, equipment and crews could delay our operations, adversely affect our ability to increase our reserves and production and reduce our cash available for distribution to our unitholders.
      Higher oil and natural gas prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could adversely affect our ability to increase our reserves and production and reduce our revenues and cash available for distribution to our unitholders.
Increases in the cost of drilling rigs, service rigs, pumping services and other costs in drilling and completing wells could reduce the viability of certain of our exploitation projects.
      The rig count and the cost of rigs and oil field services necessary to implement our exploitation projects have risen significantly with the increases in oil and natural gas prices. Increased capital requirements for our projects will result in higher reserve replacement costs which could reduce cash available for distribution. Higher project costs could cause certain of our projects could become uneconomic and therefore not be implemented, reducing our production and cash available for distribution.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
      Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable.
      In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
  •  the high cost, shortages or delivery delays of equipment and services;
 
  •  unexpected operational events;
 
  •  adverse weather conditions;
 
  •  facility or equipment malfunctions;
 
  •  title disputes;
 
  •  pipeline ruptures or spills;
 
  •  collapses of wellbore, casing or other tubulars;
 
  •  unusual or unexpected geological formations;
 
  •  loss of drilling fluid circulation;
 
  •  formations with abnormal pressures;
 
  •  fires;

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  •  blowouts, craterings and explosions; and
 
  •  uncontrollable flows of oil, natural gas or well fluids.
      Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.
      We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. 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. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Increases in interest rates, which have recently experienced record lows, will reduce our cash available for distribution
      The credit markets recently have experienced 50-year record lows in interest rates. If the overall economy strengthens, it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Based upon our debt outstanding of $106.8 million as of September 30, 2006, a 1% increase in LIBOR would result in an estimated $1,068,000 increase in annual interest expense. Additionally, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Increased interest expense and financing costs will reduce our cash available for distribution.
We may have assumed unknown liabilities in connection with the formation transactions.
      As part of the formation transactions, our properties may be subject to existing liabilities, some of which may have been unknown at the closing of our private equity offering. Unknown liabilities might include liabilities for cleanup or remediation of undisclosed or unknown environmental conditions, claims of vendors or other persons (that had not been asserted or threatened prior to this offering), tax liabilities and accrued but unpaid liabilities incurred in the ordinary course of business.
Properties that we buy may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.
      One of our growth strategies is to acquire additional oil and natural gas reserves. However, our reviews of acquired properties are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. 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 ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.
Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
      Our management team has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our acreage. We have identified, as of June 30, 2006, 117 gross (77 net) proved undeveloped drilling locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs

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and drilling results. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may be materially different from those presently identified, which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Our hedging activities could result in cash losses, could reduce our cash available for distributions and may limit potential gains.
      We have entered into, and we may in the future enter into, hedging arrangements for a significant portion of our oil and natural gas production. Many derivative instruments that we employ 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. For example, during the nine months ended September 30, 2006 our average historical unhedged sales price for oil was $62.88 per Bbl and our average historical sales price including the effects of realized hedge settlements was $49.51 per Bbl. For the same period, our average historical unhedged sales price for natural gas was $6.77 per Mcf and our average historical sales price including the effects of realized hedge settlements was $9.72 per Mcf. We settled hedges for approximately $2.2 million for the nine months ended September 30, 2006. During the nine-month period ended September 30, 2006, 77% of our oil and 72% of our natural gas production was hedged.
      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, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge. Under our credit facility, we are prohibited from hedging all of our production, and we therefore retain the risk of a price decrease on our unhedged volumes.
The inability of one or more of our customers to meet their obligations may adversely affect our financial condition and results of operations.
      Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties.
We depend on a limited number of key personnel who would be difficult to replace.
      Our operations are dependent on the continued efforts of our executive officers, senior management and key employees. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy.
We may be unable to compete effectively with larger companies, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
      The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only explore for and

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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 productive natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration and exploitation activities during periods of low oil and natural gas market prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Failure to achieve and maintain effective internal control over financial reporting in accordance with the rules of the SEC could harm our business.
      We will be required to document and test our internal control over financial reporting so that our management can certify as to the effectiveness of our internal control over financial reporting and our independent registered public accounting firm can render an opinion on management’s assessment.
      We have begun the process of evaluating and documenting our internal control over financial reporting in order to test and determine any remediation actions that may be necessary and to fully implement the requirements relating to internal controls and all other aspects of related SEC rules and the Sarbanes-Oxley Act of 2002. Since we have not prepared audited financial statements as a combined entity, our management has begun the process of implementing a system of internal controls to encompass the combined entity. We may not be able to complete our evaluation, testing and remediation actions, if any, within the time frame required by SEC rules. Any delay may have a significant impact on our reporting of our operating results or cause us to fail to meet our reporting obligations.
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 exploration and production operations are subject to complex and stringent laws and regulations. In order 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. All such costs may have a negative effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
      Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for and the production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.
      We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.

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      Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our ability to make cash distributions to our unitholders could be adversely affected.
Risks Related to this Offering and Our Limited Partnership Structure
There is no existing market for our units, and a trading market that will provide our unitholders with adequate liquidity may not develop or be sustained. The price of our units may fluctuate significantly, and our unitholders could lose all or part of their investment.
      There is no established trading market for our units and we cannot assure our unitholders as to:
  •  the likelihood that an active market will develop for the units;
 
  •  the liquidity of any such market;
 
  •  the ability of our unitholders to sell their units; or
 
  •  the price that our unitholders may obtain for their units.
      The price of our units may also be influenced by many factors, some of which are beyond our control, including:
  •  our quarterly distributions;
 
  •  our quarterly or annual earnings or those of other companies in our industry;
 
  •  announcements by us or our competitors of significant contracts or acquisitions;
 
  •  changes in accounting standards, policies, guidance, interpretations or principles;
 
  •  general economic conditions;
 
  •  publication of research reports about us or our industry; and
 
  •  future sales of our units.
Units eligible for future sale may have adverse effects on our unit price and the liquidity of the market for our units.
      We cannot predict the effect of future sales of our units, or the availability of units for future sales, on the market price of or the liquidity of the market for our units. Sales of substantial amounts of units, or the perception that such sales could occur, could adversely affect the prevailing market price of our units. Such sales, or the possibility of such sales, could also make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. In addition, if no active trading market develops for our units, sales of units or the possibility of such sales could have a greater adverse effect on the market price of our units than would be the case if an active market existed. Factors affecting the likely volume of future sales of our units, and the possible consequences of such sales, include the following:
  •  All of our units outstanding upon the completion of our private equity offering are “restricted securities” within the meaning of Rule 144 under the Securities Act. In general, upon satisfaction of certain conditions, Rule 144 permits the sale of certain amounts of restricted securities one year following the date of acquisition of the restricted securities from us or our affiliates and, after two years, permits unlimited sales by persons unaffiliated with us. As our units become eligible for sale under Rule 144, the volume of sales of our units may increase, which could reduce the market price of our units.

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  •  The Founding Investors and their affiliates, including members of our management, own approximately 72% of our outstanding units. We granted the Founding Investors certain registration rights to have their units registered under the Securities Act. Upon registration, these units will be eligible for sale into the market. Because of the substantial size of the Founding Investors’ holdings, the sale of a significant portion of these units, or a perception in the market that such a sale is likely, could have a significant impact on the market price of our units.
 
  •  We granted purchasers in our private equity offering certain registration rights to have the resale of their units registered under the Securities Act. If purchasers in our private equity offering were to resell a substantial portion of their units, it could reduce the market price of our outstanding units.
Our Founding Investors, including members of our management, own a 72% limited partner interest in us and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest and limited fiduciary duties, which may permit it to favor its own interests to the detriment of our unitholders.
      Our Founding Investors, including members of our management, own a 72% limited partner interest in us and control our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners, our Founding Investors and their affiliates. Conflicts of interest may arise between our Founding Investors and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
  •  neither our partnership agreement nor any other agreement requires our Founding Investors or their affiliates, other than our executive officers, to pursue a business strategy that favors us;
 
  •  our general partner is allowed to take into account the interests of parties other than us, such as our Founding Investors, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
 
  •  our Founding Investors and their affiliates (other than our executive officers and their affiliates) may engage in competition with us;
 
  •  our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
 
  •  our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to our unitholders;
 
  •  our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or a growth capital expenditure, which does not. Such determination can affect the amount of cash that is distributed to our unitholders;
 
  •  our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
 
  •  our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
 
  •  our general partner intends to limit its liability regarding our contractual and other obligations;

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  •  our general partner controls the enforcement of obligations owed to us by it and its affiliates; and
 
  •  our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.
Unitholders have limited voting rights and are not entitled to elect our general partner, and until we have completed an initial public offering or the owners of our general partner own less than 50% of our units, our unitholders will not be entitled to elect any of its 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 decisions regarding our business. Unitholders did not elect our general partner or its board of directors, and will have no right to elect our general partner in the future. The board of directors of our general partner will initially be chosen by the members of our general partner. Once we have completed an initial public offering resulting in proceeds of not less than $20 million that results in our units being traded on a national securities exchange or the Nasdaq Stock Market or the owners of our general partner own less than 50% of our units, all unitholders will have certain rights to participate in the election of our general partner’s board of directors. Please read “Management,” and “The Partnership Agreement — Meetings; Voting.” As a result of these limitations, the price at which the units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Even if unitholders are dissatisfied they cannot remove our general partner without the consent of unitholders owning at least 662/3% of our units, including units owned by our general partner and its affiliates.
      The unitholders are unable initially to remove our general partner without its consent because our general partner’s affiliates own sufficient units to be able to prevent our general partner’s removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Affiliates of our general partner, including members of our management, own 72% of our units.
Our partnership agreement restricts the voting rights of those unitholders owning 20% or more of our units.
      Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such 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 the unitholders’ ability to influence the manner or direction of management.
The owners of our general partner may sell all or part of the general partner to a third party without unitholder consent, which could result in a change of our management or business strategy or both and which would result in an event of default under our revolving credit facility, unless consent of our lenders is obtained.
      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 the owners of our general partner from transferring their ownership in our general partner to a third party. The new owners 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 to control the decisions taken by the board of directors and officers of our general partner until the owners of our general partner own less than 35% of our outstanding units or we have completed an initial public offering resulting

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in proceeds of not less than $20 million that results in our units being traded on a national securities exchange or the Nasdaq Stock Market. Please read “Management.”
      Additionally, certain change of control events would result in an event of default under our revolving credit facility that would allow the lenders to accelerate the maturity of our credit agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities — Our Revolving Credit Facility.”
Our Founding Investors and their affiliates (other than our executive officers and their affiliates) may compete directly with us.
      Our Founding Investors and their affiliates, other than our general partner and our executive officers and their affiliates, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our Founding Investors or their affiliates, other than our general partner and our executive officers and their affiliates, may acquire, develop and operate oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to acquire, develop or operate those assets.
Cost reimbursements due our general partner and its affiliates will reduce our cash available for distribution to our unitholders.
      Prior to making any distribution on our outstanding units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Any such reimbursement will be determined by our general partner in its sole discretion. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. Please read “Certain Relationships and Related Transactions” and “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest.” The reimbursement of expenses of our general partner and its affiliates could adversely affect our ability to pay cash distributions to our unitholders.
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.
      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 unitholder;
 
  •  provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
 
  •  provides that our general partner is entitled to make other decisions in “good faith” if it believes that the decision is in our best interest;
 
  •  provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner 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 be “fair and reasonable” to us, as determined by our general partner in good faith, and that, in determining whether a transaction or resolution is “fair and

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  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; and
 
  •  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our unitholders or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

      By purchasing a unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”
Our partnership agreement permits our general partner to redeem any partnership interests held by a limited partner who is a non-citizen assignee.
      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, our general partner may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner 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, our general partner may elect to treat the limited partner 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.
We may issue an unlimited number of additional units without the approval of our unitholders, which would dilute their existing ownership interest in us.
      Our general partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional units. The issuance by us of additional units or other equity securities of equal or senior rank will have the following effects:
  •  our unitholders’ proportionate ownership interests in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  the risk that a shortfall in the payment of our current quarterly distribution will increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the units may decline.
The liability of our unitholders 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. In some states, including Delaware, a limited partner is only liable if he participates in the “control” of the business of the partnership. These statutes generally do not define control, but do permit limited partners to engage in certain activities, including, among other actions, taking any action with respect to the dissolution of the partnership, the sale, exchange, lease or mortgage of any asset of the partnership, the admission or

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removal of the general partner and the amendment of the partnership agreement. Our unitholders could, however, be liable for any and all of our obligations as if our unitholders were a general partner if:
  •  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  our unitholders’ right to act with other unitholders to take other actions under our partnership agreement that constitute “control” of our business.
      For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement — Limited Liability.”
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
      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 a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the distribution, limited partners who received an impermissible 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. Substituted limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such substitute limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
As a public reporting company, we will incur increased costs.
      We have no history operating as a public reporting company. As a public reporting company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the stock exchanges and markets, have required changes in corporate governance practices of public companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a public reporting company, our general partner will be required to have three independent directors, create additional board committees, and maintain and report on internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our public reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We estimate these costs in the aggregate will be approximately $2.6 million annually.
Tax Risks to Unitholders
      Our unitholders should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of units.

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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, will reduce our cash available for distribution to our unitholders.
      The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.
      If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to our unitholders. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Thus, any treatment of us as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and, therefore, result in a substantial reduction in the value of our units.
      Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we will be subject to a new entity-level state tax on the portion of our income that is generated in Texas beginning for tax reports due on or after January 1, 2008. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas. If any additional states were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced.
Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
      Our unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive 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 their share of our taxable income.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the costs of any 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 that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
  Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.
      Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

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Tax gain or loss on the disposition of our units could be more or less than expected because prior distributions in excess of allocations of income will decrease our unitholders tax basis in their units.
      If our unitholders sell any of their units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a unit, which decreased their tax basis in that unit, will, in effect, become taxable income to our unitholders if the unit is sold at a price greater than their tax basis in that unit, even if the price our unitholders receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to our unitholders. In addition, if our unitholders sell units, our unitholders may incur a tax liability in excess of the amount of cash our unitholders receive from the sale.
We will treat each purchaser of our units as having the same tax benefits without regard to the 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, we will adopt depreciation 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 on the sale of units and could have a negative impact on the value of our units or result in audits of and adjustments to our unitholders’ tax returns. Please read “Material Tax Consequences — Uniformity of Units” for a further discussion of the effect of the depreciation and amortization positions we will adopt.
Our unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.
      In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We will initially do business and own assets in Texas, New Mexico, Oklahoma and Mississippi. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the units.
We will be considered to have terminated for tax purposes due to a sale or exchange of 50% or more of our interests within a twelve-month period.
      We will be considered to have terminated for 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. A constructive termination results in the closing of our taxable year for all unitholders and in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, 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 Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders.

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CAUTIONARY NOTE REGARDING 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:
  •  business strategy;
 
  •  financial strategy;
 
  •  drilling locations;
 
  •  oil and natural gas reserves;
 
  •  technology;
 
  •  realized oil and natural gas prices;
 
  •  production volumes;
 
  •  lease operating expenses, general and administrative costs and finding and development costs;
 
  •  future operating results; and
 
  •  plans, objectives, expectations and intentions.
      All of 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 the “Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and other sections of 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.
      The forward-looking statements contained in this prospectus 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 future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances 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 and elsewhere in this prospectus. The forward-looking statements in this prospectus speak only as of the date of this prospectus; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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USE OF PROCEEDS
      We will not receive any of the proceeds from the sale of units offered by this prospectus. Any proceeds from the sale of the units offered by this prospectus will be received by the selling unitholders.
CAPITALIZATION
      The following table shows:
  •  the historical capitalization of Legacy as of September 30, 2006.
      We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the audited historical consolidated balance sheet at September 30, 2006 included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
             
    As of
    September 30,
    2006
     
    Historical
     
    (Unaudited)
    (In thousands)
Debt and other obligations:
        
 
Credit facility
   $ 106,800  
       
   
Total debt and other obligations
     106,800  
Equity Capital:
        
 
Total equity
     149,558  
       
   
Total capitalization
   $ 256,358  
       

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
General
Rationale for our Cash Distribution Policy
      Our cash distribution policy reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it. The amount of available cash will be determined by our general partner for each fiscal quarter of our operation after March 15, 2006. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash on a quarterly basis. Under our partnership agreement, available cash is defined generally to mean, cash on hand at the end of each quarter, plus working capital borrowings made after the end of the quarter, less cash reserves determined by our general partner, in its sole discretion, to be necessary and appropriate to provide for the conduct of our business (including reserves for future capital expenditures, future debt service requirements, and our anticipated capital needs), comply with applicable law, any of our debt instruments or other agreements or provide for future distributions to our unitholders for any one of the upcoming four quarters. Please read “How We Make Cash Distributions.” Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case if we were subject to such tax.
Limitations on our Ability to Make Quarterly Distributions
      There is no guarantee that unitholders will receive quarterly distributions from us. Our cash distribution policy is subject to limitations and restrictions, including the following:
  •  Our general partner has broad discretion to establish reserves for the prudent conduct of our business. The establishment of those reserves could result in a reduction in the amount of cash available to pay distributions.
 
  •  Our ability to make distributions of available cash will depend primarily on our cash flow from operations. Although our partnership agreement provides for quarterly distributions of available cash, we may be unable to make distributions to our unitholders.
 
  •  If we fail to make acquisitions on economically attractive terms, we will not be able to replace our declining oil and natural gas reserves at a level that allows us to maintain our current quarterly distribution.
 
  •  We will be prohibited from borrowing under our revolving credit facility to make distributions to unitholders if the amount of borrowing outstanding under our revolving credit facility reaches or exceeds 90% of our borrowing base. Further, we may enter into future debt arrangements that could subject our ability to pay distributions to compliance with certain tests or ratios or otherwise restrict our ability to pay distributions.
 
  •  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.
 
  •  Although our partnership agreement requires us to distribute our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement can be amended with the approval of a majority of the outstanding units. Our Founding Investors, including members of our management, own an aggregate of 72% of the outstanding units, and acting jointly have the ability to amend our partnership agreement.
Our Cash Distribution Policy May Limit Our Ability to Grow
      Because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest most or all of their available cash to expand ongoing operations. We generally intend to rely upon external financing sources, including borrowings under our revolving credit facility and issuances of debt and

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equity securities, to fund a substantial portion of our acquisition expenditures and a portion of our exploitation project capital expenditures. However, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
Our Cash Distribution Policy
      Our partnership agreement provides for the distribution of available cash on a quarterly basis. Available cash, which is defined in the partnership agreement attached as Appendix A hereto and the glossary attached as Appendix B hereto, for any quarter consists of cash on hand at the end of that quarter, plus working capital borrowings made after the end of the quarter, less cash reserves determined by our general partner in its sole discretion, to be necessary and appropriate to provide for the conduct of our business (including reserves for future capital expenditures, future debt service requirements, and our anticipated capital needs), comply with applicable law, any of our debt instruments or other agreements or provide for future cash distributions to our unitholders for any one of the upcoming four quarters. Please read “How We Make Cash Distributions — Definitions of Available Cash.” The amount of available cash will be determined by our general partner for each calendar quarter of our operations.
Cash Distributions
Our Current Distribution Rate
      Our cash distribution policy currently calls for quarterly cash distributions of $0.41 per unit, or $1.64 per unit on an annualized basis, to be paid no later than 45 days after the end of each fiscal quarter. The amount of available cash, which we also refer to as cash available to pay distributions, needed to pay the current quarterly distribution on all of the units and the approximate 0.1% general partner interest outstanding for one quarter and for four quarters will be approximately:
                         
        Estimated Quarterly Distribution
         
    Number of Units   One Quarter   Four Quarters
             
Units
     18,460,349     $ 7,568,743     $ 30,274,972  
Approximate 0.1% general partner interest
     —       7,508       30,030  
                   
Total
     18,460,349     $ 7,576,251     $ 30,305,002  
                   
      We expect to be able to pay the current quarterly distribution on all of our outstanding units for each quarter through December 31, 2007.
      In the sections that follow, we present in detail the basis for our belief that we will have sufficient available cash to pay the full amount of our current quarterly distribution on all of our outstanding units for each quarter through December 31, 2007. In those sections, we present two tables:
  •  “Unaudited Pro Forma Cash Available to Pay Distributions,” in which we present the amount of available cash we would have generated on a pro forma basis for the year ended December 31, 2005 and the twelve months ended September 30, 2006; and
 
  •  “Minimum Estimated Adjusted EBITDA,” in which we present certain operating and financial assumptions for the year ending December 31, 2007.
Pro Forma Cash Available to Pay Distributions for the Year Ended December 31, 2005 and the Twelve Months Ended September 30, 2006
      You should be aware that our pro forma cash available to pay distributions for the year ended December 31, 2005 would not have been sufficient to pay the full annualized current quarterly distribution of $1.64 per unit on all units outstanding.
      If we had completed our private equity offering and related formation transactions, including the acquisition of the properties acquired in those transactions, the South Justis and Kinder Morgan acquisitions, on January 1, 2005, pro forma cash available to pay distributions generated during the year ended

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December 31, 2005 would have been approximately $28.1 million. This amount of pro forma cash available to pay distributions would have been sufficient to allow us to pay approximately 93% of the current quarterly distributions on our units during this period. However, our pro forma cash available to pay distributions for the twelve months ended September 30, 2006 would have been sufficient to pay the full annualized distribution.
      The following table illustrates, on a pro forma basis, for the year ended December 31, 2005 and the twelve months ended September 30, 2006, the amount of cash available to pay distributions to our unitholders, assuming that our private equity offering and the related formation transactions our recent acquisitions had been consummated at the beginning of 2005.
      We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had our private equity offering and related formation transactions and the South Justis and Kinder Morgan acquisitions actually been completed as of January 1, 2005. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available to pay distributions only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.
Legacy Reserves LP
Unaudited Pro Forma Cash Available to Pay Distributions
                   
    Year Ended   Twelve Months
    December 31,   Ended September 30,
    2005   2006
         
    (In thousands, except per unit
    amounts)
Net Income
   $ 5,507     $ 13,948  
Plus:
                
 
Interest expense
     6,928       7,651  
 
Depletion, depreciation, amortization and accretion
     18,063       20,619  
 
Impairment of long-lived assets
     6       8,578  
 
Gain on sale of assets
     (299 )     (323 )
 
Unrealized loss on oil and natural gas swaps
     4,027       (8,337 )
             
Adjusted EBITDA
   $ 34,232     $ 42,136  
             
Less:
                
 
Cash interest expense(a)
     6,818       6,992  
 
Pro forma additional expense of being a public reporting company(b)
     422       422  
Add:
                
 
Pro forma reduction of expenses to operate the South Justis Unit(c)
     570       419  
 
Realized loss on cancelled swaps
     4,319 (d)     3,976 (e)
             
Pro forma operating cash flow
   $ 31,881     $ 39,117  
             
 
Less: Exploitation capital expenditures(f)
     3,761       5,210  
             
Pro forma cash available to pay distributions
   $ 28,120     $ 33,907  
             
Pro forma cash distributions
                
 
Annualized current quarterly distribution per unit
   $ 1.64     $ 1.64  
             
 
Total distributions
   $ 30,305     $ 30,305  
             
Excess (shortfall)
   $ (2,185 )   $ 3,602  
             

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(a) Interest expense has been adjusted to exclude amortization of deferred financing fees which are non-cash items.
 
(b) As a result of becoming a public reporting company, we expect our incremental general and administrative expenses to include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, fees of independent directors, accounting fees and legal fees. We estimate these costs will be $2.5 million annually in excess of the costs we estimate would be incurred if we were a private company and $422,000 higher than our pro forma 2005 and twelve months ended September 30, 2006 general and administrative costs, which include approximately $1.3 million and $1.9 million of general and administrative expenses associated with our private equity offering, respectively.
 
(c) As a result of our acquisition of the oil and natural gas properties in the South Justis Unit and the related operating rights, we estimate we will incur $570,000 and $419,000 less in general and administrative expenses than the amounts allocated by the seller for the year ended December 31, 2005 and the twelve months ended September 30, 2006, respectively.
 
(d) Includes approximately $3.5 million of derivative premiums for the year ended December 31, 2005 to cancel and reset 2006 oil swaps from $51.31 to $59.38 per Bbl and approximately $0.8 million of premiums paid on July 22, 2005 for an option to enter into a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised.
 
(e) Includes the effect of approximately $4.0 million of derivative premiums to cancel and reset 2007 oil swaps from $60.00 to $65.82 per barrel for 372,000 barrels and for 2008 oil swaps from $60.50 to $66.44 per barrel for 348,000 barrels, which reflected the prevailing oil swap market at the time of reset.
 
(f) Does not include capital expenditures associated with the PITCO properties or our recent acquisitions in each case prior to their date of acquisition.
      As a result of the factors described in “— Minimum Estimated Adjusted EBITDA” and “— Assumptions and Considerations” below, we believe we will be able to pay the current quarterly distribution of $0.41 per unit on all units for each quarter through December 31, 2007.
Minimum Estimated Adjusted EBITDA
      In order to fund the current quarterly distribution of $0.41 per unit for the year ending December 31, 2007, our cash available to pay distributions must be at least $30.3 million over that period. We have calculated the minimum estimated Adjusted EBITDA for the year ending December 31, 2007 that is necessary to generate the amount of available cash necessary to pay the current quarterly distribution over that period, which we refer to as the Minimum Estimated Adjusted EBITDA.
      We define Adjusted EBITDA as net income (loss) plus:
  •  Interest expense;
 
  •  Depletion, depreciation, amortization and accretion;
 
  •  Impairment of long-lived assets;
 
  •  (Gain) loss on sale of partnership investment;
 
  •  (Gain) loss on sale of assets;
 
  •  Equity in (income) loss of partnerships; and
 
  •  Unrealized (gain) loss on oil and natural gas swaps.
      Adjusted EBITDA is a financial measurement that we will report to our lenders and use as a gauge for compliance with our EBITDA-to-interest covenant in our revolving credit facility. Please read “Manage-

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ment’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities — Our Revolving Credit Facility.”
      Adjusted EBITDA is also used as a supplemental performance measure by our management and by external users of our financial statements such as industry analysts, investors, lenders, rating agencies and others to assess:
  •  the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
 
  •  our operating performance and return on capital as compared to those of other companies in the exploration and production industry, without regard to financing or capital structure.
      Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
      In the table below entitled “Minimum Estimated Adjusted EBITDA,” we calculate that our Minimum Estimated Adjusted EBITDA must be approximately $48.7 million for the year ending December 31, 2007 for us to be able to generate cash available to pay distributions of $30.3 million. Although we believe that we will be able to achieve these results based on the assumptions and considerations set forth later in this section, we can give you no assurance that we will actually generate the Minimum Estimated Adjusted EBITDA and estimated available cash needed to pay the current quarterly distributions through December 31, 2007. There will likely be differences between these amounts and our actual results and those differences could be material. If we are not able to achieve the Minimum Estimated Adjusted EBITDA described above, we may not be able to fully fund the current quarterly distribution or any amount on our outstanding units.
      In calculating the Minimum Estimated Adjusted EBITDA, we have included estimates of capital expenditures for the year ending December 31, 2007. The Minimum Estimated Adjusted EBITDA includes our assumption that we will make capital expenditures associated with drilling 22 gross (12.9 net) development wells, executing 24 gross (4.1 net) recompletions and refracture stimulations and expanding one tertiary (CO2) recovery project during the year ending December 31, 2007 that will be funded with cash flow from operations. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business.”
      You should read “— Assumptions and Considerations” below for a discussion of the material assumptions underlying our belief that we will be able to generate the Minimum Estimated Adjusted EBITDA in the amount disclosed for the year ending December 31, 2007. Our belief is based on certain assumptions and reflects our judgment, as of the date of this prospectus, regarding conditions we expect to exist and the course of action we expect to take during the year ending December 31, 2007. The assumptions we disclose are those that we believe are significant to our ability to generate the Minimum Estimated Adjusted EBITDA shown. If these estimates prove to be materially incorrect, we may not be able to fully fund the current quarterly distribution or any amount on our outstanding units.
      Our calculation of Minimum Estimated Adjusted EBITDA for the year ending December 31, 2007 has been prepared by our management. Our independent auditors have not examined, compiled, or otherwise applied procedures to our Minimum Estimated Adjusted EBITDA for the year ending December 31, 2007 and, accordingly, do not express an opinion or any other form of assurance on this estimate.
      When considering our Minimum Estimated Adjusted EBITDA for the year ending December 31, 2007, you should keep in mind the risk factors and other cautionary statements in “Risk Factors,” “Forward-Looking Statements” and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial condition and results of operations to vary materially from those set forth in the table below. In addition, we do not undertake any obligation to release the results of any future revisions we may make to these estimates or to update these estimates to reflect events or circumstances after the date of this prospectus. Therefore, we caution you not to place undue reliance on this information.

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Minimum Estimated Adjusted EBITDA
             
    Year Ending
    December 31,
    2007
     
    (In thousands,
    except per unit
    amounts)
Minimum Estimated Adjusted EBITDA
   $ 48,668  
Less:
        
 
Cash interest expense(a)
     8,054  
 
Capital expenditures(b)
     10,309  
       
Minimum cash available to pay distributions
   $ 30,305  
       
Estimated cash distributions
        
 
Annualized current quarterly distribution per unit
   $ 1.64  
       
 
Distributions to outside investors and others
     8,440  
 
Distributions to Founding Investors, directors and management
     21,835  
 
Distributions to our general partner
     30  
       
   
Total estimated distributions to be paid
   $ 30,305  
       
 
(a) Cash interest expense is based on our estimated average debt balance of $111 million and an assumed interest rate of 7.25%.
 
(b) We expect we will make capital expenditures associated with drilling of 22 gross (12.9 net) development wells, executing 24 gross (4.1 net) recompletions and refracture stimulations and expanding one tertiary (CO2) recovery project during the year ending December 31, 2007.

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      As reflected in the table below, to generate our Minimum Estimated Adjusted EBITDA for the year ending December 31, 2007, we have assumed the following regarding our operations, revenues and expenses for that period:
                 
    Year Ending
    December 31,
    2007
     
Net Production(a):
        
 
Oil (MBbls)
     979  
 
Natural gas and products (MMcf)
     2,263  
     
Total oil equivalent production (MBoe)
     1,356  
     
Average oil equivalent daily production (Boe/d)
     3,715  
Average Oil Sales Price per Bbl(b):
        
 
Average NYMEX sales price (hedged volumes)
   $ 67.62  
 
Average NYMEX sales price (unhedged volumes)
   $ 65.00  
 
Weighted average NYMEX sales price
   $ 66.80  
 
Percent of total oil production hedged
     69 %
   
(Discount) to NYMEX
   $ (4.13 )
 
Weighted average net sales price
   $ 62.67  
Average Natural Gas Sales Price per Mcf(c):
        
 
Average NYMEX sales price (hedged volumes)
   $ 9.56  
 
Average NYMEX sales price (unhedged volumes)
   $ 8.00  
 
Weighted average NYMEX sales price
   $ 9.07  
 
Percent of total natural gas production hedged
     69 %
 
(Discount) to NYMEX
   $ (1.19 )
 
Weighted average net sales price
   $ 7.88  
Minimum Estimated Adjusted EBITDA (in thousands):
        
 
Total revenue(d)
   $ 79,176  
 
Operating expenses(e)
     (20,876 )
 
General and administrative expenses(f)
     (3,352 )
       
   
Estimated Adjusted EBITDA
     54,948  
     
less:
        
     
Excess Estimated Adjusted EBITDA(g)(h)(i)
     6,280  
       
       
Minimum Estimated Adjusted EBITDA
   $ 48,668  
       
 
(a) Net production volumes are based on oil and natural gas production from reserve reports (as of June 30, 2006), prepared by LaRoche Petroleum Consultants, Ltd.
 
(b) Our weighted average oil sales price of $62.67 per Bbl is calculated taking into account the volume of oil we have hedged for the year ending December 31, 2007 (671,637 Bbls, or approximately 69% of total forecasted oil production volume) at a weighted average price of $67.62 per Bbl and unhedged oil production volumes at an assumed price of $65.00 per Bbl.
 
(c) Our weighted average net natural gas sales price of $7.88 per Mcf is calculated by taking into account the volume of natural gas we have hedged for the year ending December 31, 2007 (1,558,504 MMBtu, or approximately 69% of total forecasted production volume) at a weighted average NYMEX price of $9.56 per Mcf and unhedged natural gas production volumes at an assumed NYMEX price of $8.00 per Mcf.

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(d) Revenue is equal to (i) the product obtained by multiplying total net oil production by the weighted average net oil sales prices, plus (ii) the product obtained by multiplying total net natural gas production by the weighted average net natural gas sales prices.
 
(e) Operating expenses consist of the lease operating expenses, labor, field office rent, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, production taxes and other customary charges.
 
(f) General and administrative expenses are based on our estimate of the costs of our employees and our general partner’s executive officers, related benefits, office leases, professional fees, other costs not directly associated with field operations and the additional costs associated with being a public reporting company net of operator fees paid to us by third party owners in properties we operate.
 
(g) We are required by the terms of our partnership agreement to distribute all of our available cash in each quarter to the extent there is any after the establishment of cash reserves. Please read “How We Make Cash Distributions — Definition of Available Cash.” Should we generate amounts in excess of the Minimum Estimated Adjusted EBITDA our general partner may establish cash reserves that would prevent us from having available cash in excess of the amount required to pay the full amount of our current quarterly distribution on all units.
 
(h) The Excess Estimated Adjusted EBITDA for the year ending December 31, 2007 was favorably impacted by approximately $2.0 million due to the cancellation and reset of certain oil swaps. On September 25, 2006, we cancelled and reset 2007 oil swaps from $60.00 to $65.82 per barrel for 372,000 barrels and for 2008 oil swaps from $60.50 to $66.44 per barrel for 348,000 barrels which reflected the prevailing swap market at the time of the reset. Our $4.0 million payment to cancel the subject oil swaps has been reflected as a realized hedge loss in our statement of operations and adversely affected Adjusted EBITDA for the nine months ended September 30, 2006. Of the $4.0 million payment, $2.1 million relates to the cancellation of the 2007 oil swaps and $1.9 million relates to cancellation of the 2008 oil swaps.
 
(i) The Excess Estimated Adjusted EBITDA computation for the twelve month period ending September 30, 2007 is not presented herein. For the twelve month period ending September 30, 2007, the Excess Estimated Adjusted EBITDA, which was favorably impacted by $1.4 million due to the oil swap cancellation and reset as described in footnote (h) above, would have been $0.5 million.
      Our year ending December 31, 2007 Estimated Adjusted EBITDA would change based on different average NYMEX oil and NYMEX natural gas unhedged sales prices. If the average NYMEX unhedged sales prices decreased by $5.00 per Bbl and $1.00 per Mcf for oil and natural gas respectively, the Estimated Adjusted EBITDA would decrease by $1.7 million to $53.2 million.
Assumptions and Considerations
      We believe, based on the specific assumptions with respect to the year ending December 31, 2007 that are outlined below, that we will generate sufficient cash flow from operations to enable us to pay the full amount of our current quarterly distribution on all units for each quarter through December 31, 2007. While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full amount of our current quarterly distribution, or any amount, on all units, in which event the market price of our units may decline substantially. Consequently, the statement that we believe that we will generate sufficient available cash to pay the full amount of our current quarterly distribution on all units for each quarter through December 31, 2007 should not be regarded as a representation by us or any other person that we will make these distributions. When reading this section, you should keep in mind the risk factors and other cautionary

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statements in “Risk Factors,” “Forward-Looking Statements” and elsewhere in this prospectus. Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.
Operations and Revenue
  •  We expect to drill 22 gross (12.9 net) development wells and to execute 24 gross (4.1 net) recompletions and refracture stimulations and one tertiary (CO2) recovery expansion project during the year ending December 31, 2007, 100% of which we assume will be successful in producing oil or natural gas in commercial quantities. During the period January 1, 2003 through September 30, 2006, we drilled 38 gross (8.1 net) development wells, excluding activities that occurred on the PITCO properties prior to our acquisition of them, of which 36 gross (7.4 net) produce oil or natural gas in commercial quantities.
 
  •  We estimate, based on our reserve report, that our total net production will be 1,356 MBoe for the year ending December 31, 2007. Our net production on a consolidated combined basis including production from all the properties we owned as of September 30, 2006 for the twelve months ended September 30, 2006 and the year ended December 31, 2005 was 1,276 MBoe and 1,334 MBoe, respectively.
 
  •  We estimate that we will achieve a weighted average oil sales price of approximately $62.67 for the year ending December 31, 2007, based on the fact that we have hedged approximately 69% of our forecasted oil production for the period (671,637 Bbls) at a weighted average NYMEX oil price of $67.62 per Bbl. We have assumed a NYMEX oil price of $65.00 per Bbl for our unhedged volumes. Our estimated weighted average oil price also includes an assumed discount of $4.13 per Bbl, which accounts for our estimate of the Permian Basin basis differential relative to the NYMEX price. On a consolidated combined basis (including production from all the properties we owned as of September 30, 2006) for the twelve months ended September 30, 2006 and the year ended December 31, 2005, our average realized oil sales prices (including the effect of cash settlements on swaps) were $52.05 per Bbl and $43.96 per Bbl, respectively.
 
  •  We estimate that we will achieve a weighted average natural gas sales price of approximately $7.88 per Mcf for the year ending December 31, 2007, based on the fact that we have hedged approximately 69% of our forecasted natural gas production for the period (1,558,504 MMBtu) at a weighted average NYMEX natural gas price of $9.56 per Mcf. We have assumed a NYMEX natural gas price of $8.00 per Mcf for our unhedged volumes. Our estimated weighted average natural gas sales price also includes an assumed discount of $1.19 per Mcf, which accounts for our estimate of the Permian Basin basis differential relative to the NYMEX price and positive Btu adjustments, less gathering fees. On a consolidated combined basis (including production from all the properties we owned as of September 30, 2006) for the twelve months ended September 30, 2006 and the year ended December 31, 2005 our average realized natural gas sales prices (including the effect of cash settlements on swaps) was $9.68 per Mcf and $6.70 per Mcf, respectively.
 
  •  We estimate that we will generate revenues of approximately $79.2 million for the year ending December 31, 2007, which we have calculated by multiplying the total estimated net oil and natural gas production by the respective weighted average oil and natural gas sales price estimates described above. For the twelve months ended September 30, 2006 and the year ended December 31, 2005, we generated oil and natural gas sales of $71.2 million and $64.1 million, respectively, prior to the effects of hedging. The estimated increase in revenues for the year ending December 31, 2007 compared to the twelve months ended September 30, 2006, is attributable to a 6.3% increase in average production and a 10.7% increase in the price of oil, offset by a 19% reduction in the price of natural gas. Realized hedge losses for the twelve months ended September 30, 2006 and the year ended December 31, 2005 were $2.4 million and $7.0 million, respectively. The realized hedge losses for the twelve months ended September 30, 2006 include approximately $4.0 million of payments to cancel and reset 2007 oil swaps from $60.00 to $65.82 per barrel for 372,000 barrels and for 2008 oil swaps from $60.50 to $66.44 per barrel for 348,000 barrels which reflected the prevailing swap market at the

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  time of the reset. The realized hedge losses for the year ended December 31, 2005 include approximately $3.5 million of payments to terminate 2006 oil swaps priced at $51.31 per Bbl and enter into swaps on the same oil volumes priced at $59.38 per Bbl, and approximately $0.8 million of premiums paid for an option to enter into a $55.00 per Bbl oil swap related to the PITCO properties acquisition that was not exercised.
Capital Expenditures and Expenses
  •  We estimate that our capital expenditures for the year ending December 31, 2007 will be approximately $10.3 million, based on our expectation of drilling 22 gross (12.9 net) development wells and executing 24 gross (4.1 net) recompletions and refracture stimulations and expanding one tertiary (CO2) recovery project during the year. We expect to finance these capital expenditures with cash flow from operations. Excluding the PITCO properties prior to our purchase on September 14, 2005, for the twelve months ended September 30, 2006 and the year ended December 31, 2005, we drilled 15 gross (3.3 net) and 12 gross (1.6 net) development wells, respectively. Capital expenditures over the twelve months ended September 30, 2006 and the year ended December 31, 2005 were $5.2 million and $3.8 million, respectively. The increase in estimated capital expenditures for the year ending December 31, 2007 compared to the prior periods is attributable to our expanded property base with the PITCO properties and the South Justis, Farmer Field and Kinder Morgan acquisitions, to the drilling and recompletion of more net wells, and increases in drilling costs.
 
  •  We estimate that our operating expenses for the year ending December 31, 2007 will be approximately $20.9 million. For the twelve months ended September 30, 2006 and the year ended December 31, 2005, our pro forma operating expenses were approximately $21.9 million and $19.2 million, respectively.
 
  •  We estimate that our general and administrative expenses for the year ending December 31, 2007 will be approximately $3.4 million. For the twelve months ended September 30, 2006 and the year ended December 31, 2005, our pro forma general and administrative expenses were $5.1 million and $3.1 million, respectively, which include $1.9 million and $1.3 million of general and administrative expenses associated with our private equity offering, respectively. The general and administrative expenses for all three periods are net of operating fees paid by third party owners in our operated properties. In 2007, we expect to receive a full year of operating fees from the properties we acquired in the South Justis and Kinder Morgan acquisitions, which serves to reduce our general and administrative expense.
 
  •  We estimate that our interest expense for the year ending December 31, 2007 will be approximately $8.1 million, based on our expected average debt balance of approximately $111 million and an assumed interest rate of 7.25%. For the twelve months ended September 30, 2006 and the year ended December 31, 2005, our pro forma interest expense was $7.7 million and $6.9 million, respectively.
Other
  •  We assume that we will not incur expenses relating to the cancellation of commodity swaps.
 
  •  We assume that there will be no material nonperformance or credit-related defaults by equipment suppliers, drillers, purchasers or counterparties to our oil and natural gas swaps.
 
  •  We assume that no material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated material events will occur in either our existing operations or our planned drilling program.
 
  •  We assume that market, regulatory and overall economic conditions will not change substantially.

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HOW WE MAKE CASH DISTRIBUTIONS
Definition of Available Cash
      We define available cash in the glossary, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter:
  •  less the amount of cash reserves established by our general partner, in its sole discretion, to:
  •  provide for the proper conduct of our business (including reserves for future capital expenditures, future debt service requirements, and for our anticipated credit needs);
 
  •  comply with applicable law, any of our debt instruments or other agreements; or
 
  •  provide funds for distribution to our unitholders for any one or more of the next four quarters;
  •  plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to unitholders.
Distributions of Cash Upon Liquidation
      If we dissolve in accordance with our 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 our 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.
Adjustments to Capital Accounts
      We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation.

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SELECTED HISTORICAL AND PRO FORMA
CONSOLIDATED FINANCIAL DATA
      We were formed in October 2005. Upon completion of our private equity offering and as a result of the related formation transactions on March 15, 2006, we acquired oil and natural gas properties and business operations from the Founding Investors and the three charitable foundations. Although we were the surviving entity for legal purposes, the formation transactions were treated as a purchase with Moriah Properties, Ltd. and its affiliates, or the Moriah Group, being considered, on a combined basis, as the acquiring entity for accounting purposes. As a result, Legacy Reserves LP (formerly the Moriah Group) applied the purchase method of accounting to the separable assets, and the liabilities of the oil and natural gas properties acquired from the Founding Investors (other than the Moriah Group) and the charitable foundations. Our historical financial statements for periods prior to March 15, 2006 only reflect the accounts of the Moriah Group.
      The following table shows selected historical and pro forma financial and operating data for Legacy Reserves LP for the periods and as of the dates indicated. Through March 15, 2006, Legacy’s accompanying consolidated historical financial statements reflect the accounts of the Moriah Group, which includes the accounts of Moriah Resources, Inc. as the general partner of Moriah Properties, Ltd., Moriah Properties, Ltd., the oil and natural gas interests individually owned by Dale A. and Rita Brown until October 1, 2005 when those interests were transferred to DAB Resources, Ltd. and the accounts of MBN Properties LP. The Moriah Group consolidated MBN Properties LP as a variable interest entity with the portion of net income (loss) applicable to the other owners’ equity interests being eliminated through a non-controlling interest adjustment. Although MBN Management, LLC, the general partner of MBN Properties LP, is also a variable interest entity, it was accounted for by the Moriah Group using the equity method. From March 15, 2006, Legacy’s historical financial statements include the results of operations of the oil and natural gas properties acquired from the Founding Investors (other than the Moriah Group) and the charitable foundations.
      The selected historical financial data of Legacy for the years ended December 31, 2001 and 2002 is derived from the consolidated financial statements of the Moriah Group. The selected historical financial data of the Moriah Group for the years ended December 31, 2003, 2004 and 2005 are derived from the audited consolidated financial statements of Legacy included elsewhere in this prospectus. Since the PITCO properties were not acquired by MBN Properties LP until September 14, 2005, the combined results of operations for Legacy for the year ended December 31, 2005 only include the operating results for the PITCO properties for the period from September 14, 2005 through December 31, 2005.
      The unaudited selected pro forma financial data of Legacy is derived from the unaudited pro forma financial statements of Legacy included elsewhere in this prospectus. The pro forma statements of operations give pro forma effect to (i) the formation of MBN Properties LP and its acquisition of properties from PITCO, (ii) the private equity offering and the related formation transactions (iii) the acquisition of the South Justis Unit properties from Henry Holding LP and (iv) the acquisition of properties from Kinder Morgan. The pro forma adjustments have been prepared as if the transactions had taken place on January 1, 2005, in the case of the pro forma statements of operations for the year ended December 31, 2005 and the nine months ended September 30, 2006. The unaudited selected pro forma financial data are not necessarily indicative of operating results or the financial position that would have been achieved had the events described above been completed on those dates and are not necessarily indicative of future operating results.
      You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Legacy’s financial statements and related notes included elsewhere in this prospectus. You should also read the pro forma information together with the unaudited pro forma financial statements of Legacy Reserves LP and related notes included elsewhere in this prospectus.

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      The following table presents the non-GAAP financial measures which we are required to report to our lenders in order to satisfy financial covenants under our revolving credit facility Adjusted EBITDA, Ratio of Adjusted EBITDA to interest expense and Adjusted current ratio. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financing Activities — Our Revolving Credit Facility.” These measures are not calculated or presented in accordance with generally accepted accounting principles, or GAAP. These measures are presented because such information is relevant and is used to assess compliance with our loan covenants. Adjusted EBITDA is also used as a supplemental performance measure by our management and by external users of our financial statements to assess the financial performance, operational performance and return on capital of our assets as compared to other companies in the exploration and production industry without regard to financing methods, capital structure or historical cost basis. We explain these measures below and reconcile them to the most directly comparable financial measures calculated and presented in accordance with GAAP in “— Non-GAAP Financial Measures” beginning on page 21.
                                                                           
    Historical   Pro Forma
         
        Nine Months    
        Ended       Nine Months
    Year Ended December 31,   September 30,   Year Ended   Ended
            December 31,   September 30,
    2001   2002   2003   2004   2005(a)   2005(a)   2006(b)   2005(c)   2006(c)
                                     
    (Unaudited)                           (Unaudited)
    (In thousands)
Statement of Operations Data:
                                                                        
Revenues:
                                                                        
 
Oil sales
   $ 5,590     $ 5,494     $ 7,919     $ 10,998     $ 18,225     $ 11,419     $ 32,444     $ 46,357     $ 40,461  
 
Natural gas sales
     3,340       2,204       3,697       3,945       7,318       3,872       10,822       16,167       12,006  
 
Realized and unrealized gain (loss) on oil and natural gas swaps
     (167 )     (594 )     (283 )     (633 )     (6,159 )     (7,649 )     5,534       (11,048 )     4,229  
                                                       
Total revenues
     8,763       7,104       11,333       14,310       19,384       7,642       48,800       51,476       56,696  
                                                       
Expenses:
                                                                        
 
Oil and natural gas production
     2,735       2,586       3,496       4,345       6,376       3,610       10,160       14,637       12,530  
 
Production and other taxes
     541       459       661       928       1,636       1,140       2,710       4,152       3,421  
 
General and administrative
     261       230       543       731       1,354       439       3,265       3,056       3,769  
 
Dry hole costs
     173       261       1,465       1       —       —       —       206       —  
 
Depletion, depreciation, amortization and accretion
     1,405       649       766       883       2,291       736       12,702       18,063       15,912  
 
Impairment of long-lived assets
     205       —       471       —       —       —       8,573       6       8,573  
 
(Gain) loss on sale of assets
     (228 )     —       —       —       20       —       —       (299 )     —  
                                                       
 
Total expenses
     5,092       4,185       7,402       6,888       11,677       5,925       37,410       39,821       44,205  
                                                       
 
Operating income
     3,671       2,919       3,931       7,422       7,707       1,717       11,390       11,655       12,491  
Other income (expense):
                                                                        
 
Interest income
     7       14       56       419       185       153       94       639       94  
 
Interest expense
     (154 )     (50 )     (94 )     (213 )     (1,584 )     (293 )     (4,512 )     (6,928 )     (5,732 )
 
Gain on sale of partnership investment
     —       —       —       1,292       —       —       —       —       —  
 
Equity in income (loss) of partnerships
     —       (44 )     311       183       (495 )     (338 )     (318 )     —       —  
 
Other
     4       4       3       92       45       45       15       141       22  
                                                       
 
Income before non-controlling interest
     3,528       2,843       4,207       9,195       5,858       1,284       6,669       5,507       6,875  
 
Non-controlling interest
     —       —       —       —       1       1       —       —       —  
                                                       
 
Income from continuing operations
     3,528       2,843       4,207       9,195       5,859       1,285       6,669     $ 5,507     $ 6,875  
                                                       

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    Historical   Pro Forma
         
        Nine Months    
        Ended       Nine Months
    Year Ended December 31,   September 30,   Year Ended   Ended
            December 31,   September 30,
    2001   2002   2003   2004   2005(a)   2005(a)   2006(b)   2005(c)   2006(c)
                                     
    (Unaudited)                           (Unaudited)
    (In thousands)
Discontinued operations:
                                                                        
 
Income (loss) from operations
     —       (192 )     10       15       —       —       —                  
 
Gain on disposal
     —       463       233       7       —       —       —                  
                                                       
 
Income from discontinued operations
     —       271       243       22       —       —       —                  
                                                       
Cumulative effect of accounting change
   —
 
$		 3,528     —
 
$		 3,114       (223 )
 
$4,227		   —
 
$		 9,217     —
 
$		 5,859       —
 
1,285		     —
 
$		 6,669                  
 
Net Income
                                                                        
                                                       
Earnings (loss) per unit from continuing operations:
   $ 0.37     $ 0.30     $ 0.44     $ 0.97     $ 0.62     $ 0.14     $ 0.42     $ 0.30     $ 0.37  
 
Basic and fully diluted
                                                                        
                                                       
Cash Flow Data:
                                                                        
 
Net cash provided by operating activities
   $ 4,680     $ 3,941     $ 6,799     $ 8,586     $ 14,409     $ 10,124     $ 21,818                  
 
Net cash provided by (used in) investing activities
   $ 1,874     $ (1,895 )   $ (8,475 )   $ 1,023     $ (68,965 )   $ (70,076 )   $ (53,827 )                
 
Net cash provided by (used in) financing activities
   $ (6,571 ) $1,223   $ (1,993 ) $2,741   $ 1,717 $4,047     $ (8,958 ) $3,325   $ 55,742 $66,915     $ 60,894 $65,498     $ 31,698 $45,553                  
 
Capital expenditures
                                                                        
Other Financial Information (unaudited):
           $ 4,417     $ 4,907     $ 9,397     $ 12,877     $ 6,770     $ 25,059     $ 34,232     $ 31,145  
 
Adjusted EBITDA(d)
                                                                        
 
Ratio of Adjusted EBITDA to interest expense(e)
             88.3 x     52.2 x     44.1 x     8.1 x     23.1 x     5.6 x     4.9 x     5.4 x
 
(a)  Reflects MBN Properties LP’s purchase of the PITCO properties on September 14, 2005. Consequently, the operations of the PITCO properties are only included for the period following the date of acquisition.
 
(b)  Reflects Legacy’s purchase of the oil and natural gas properties acquired in the March 15, 2006 formation transactions and the South Justis, Farmer Field and Kinder Morgan acquisitions. Consequently, the operations of these acquired properties are only included for the period from the closing dates of such acquisitions through September 30, 2006.
 
(c)  Do not reflect the Farmer Field acquisition.
 
(d)  Please read “— Non-GAAP Financial Measures” beginning on page 21.
 
(e)  Our revolving credit facility requires us to maintain consolidated net income plus interest expense, income, taxes, depreciation, depletion, amortization and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0.

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    Historical
     
    As of December 31,   As of
        September 30,
    2001   2002   2003   2004   2005   2006
                         
    (Unaudited)                   (Unaudited)
    (In thousands)
Balance Sheet Data:
                                                
 
Cash and cash equivalents
   $ 22     $ 76     $ 117     $ 769     $ 1,955     $ 1,644  
 
Other current assets
     1,002       2,643       7,826       5,799       6,316       14,413  
 
Oil and natural gas properties, net of accumulated depletion, depreciation and amortization
     6,823       7,558       9,954       12,224       77,172       249,049  
 
Other assets
     78       497       651       —       1,499       7,736  
                                     
 
Total assets
   $ 7,925     $ 10,774     $ 18,548     $ 18,792     $ 86,942     $ 272,842  
                                     
 
Current Liabilities
   $ 407     $ 3,925     $ 9,157     $ 4,898     $ 4,562     $ 8,669  
 
Long-term debt
     —       —       —       —       52,473       106,800  
 
Other long-term liabilities
             —       2,113       1,872       19,998       7,815  
 
Owners’ equity
     7,518       6,849       7,278       12,022       9,909       149,558  
                                     
 
Total liabilities and owners’ equity
   $ 7,925     $ 10,774     $ 18,548     $ 18,792     $ 86,942     $ 272,842  
                                     

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
      The following discussion and analysis should be read in conjunction with the “Selected Historical and Pro Forma Consolidated Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
Overview
      We were formed in October 2005. Upon completion of our private equity offering and as a result of the related formation transactions on March 15, 2006, we acquired oil and natural gas properties and business operations from our Founding Investors and three charitable foundations. Although we were the surviving entity for legal purposes, the formation transactions are treated as a purchase with Moriah Properties, Ltd. and its affiliates, or the Moriah Group, being considered, on a combined basis, as the acquiring entity for accounting purposes. Therefore, the accounts reflected in our historical financial statements prior to March 15, 2006 are those of the Moriah Group.
      The Moriah Group owned and operated oil and natural gas producing properties located primarily in the Permian Basin of West Texas and southeast New Mexico. The Moriah Group included the accounts of Moriah Resources, Inc. as the general partner of Moriah Properties, Ltd., the oil and natural gas interests individually owned by Dale A. and Rita Brown until October 1, 2005 when those interests were transferred to DAB Resources, Ltd. and the accounts of MBN Properties LP. The Moriah Group consolidated MBN Properties LP as a variable interest entity with the portion of net income (loss) applicable to the other owners’ equity interests eliminated through a non-controlling interest adjustment. Although MBN Management, LLC, the general partner of MBN Properties LP, is also a variable interest entity, it was accounted for by the Moriah Group using the equity method.
      Because of our rapid growth through acquisitions and development of properties, historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results. Since the PITCO properties were not acquired by MBN Properties LP until September 14, 2005, the results of operations for the year ended December 31, 2005 only include the operating results for the PITCO properties for the period of September 14, 2005 through December 31, 2005. The operating results of the properties acquired in the formation transactions are also included in the results of operations from March 15, 2006, the operating results of the South Justis Unit properties and the Farmer Field properties acquired on June 29, 2006 have been included from July 1, 2006 and the operating results of the Kinder Morgan properties have been included from August 1, 2006.
      Acquisitions have been financed with a combination of proceeds from bank borrowings and issuances of units and cash flow from operations. Post-acquisition activities are focused on evaluating and exploiting the acquired properties and evaluating potential add-on acquisitions.
Legacy Reserves LP
      Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial

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position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
      Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs. Given the inherent volatility of oil and natural gas prices, which are influenced by many factors beyond our control, we plan our activities and budget based on sales price assumptions which historically have been lower than the average sales prices received. We focus our efforts on increasing oil and natural gas production and reserves while controlling costs at a level that is appropriate for long-term operations.
      We face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. We attempt to overcome this natural decline by utilizing multiple types of recovery techniques such as secondary (waterflood) and tertiary (CO2) recovery methods to repressure the reservoir and recover additional oil, drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on adding reserves through acquisitions and exploitation projects. Our ability to add reserves through acquisitions and exploitation projects is dependent upon many factors including our ability to raise capital, obtain regulatory approvals and contract drilling rigs and personnel.
      Our revenues are highly sensitive to changes in oil and natural gas prices and to levels of production. As set forth under “Cash Flow from Operations” below, we have hedged a significant portion of our expected production, which allows us to mitigate, but not eliminate, oil and natural gas price risk. We continuously conduct financial sensitivity analyses to assess the effect of changes in pricing and production. These analyses allow us to determine how changes in oil and natural gas prices will affect our ability to execute our capital investment programs and to meet future financial obligations. Further, the financial analyses allow us to monitor any impact such changes in oil and natural gas prices may have on the value of our proved reserves and their impact, if any, on any redetermination to our borrowing base under our credit facility.
      Legacy does not specifically designate derivative instruments as cash flow hedges; therefore, the mark-to-market adjustment reflecting the unrealized gain or loss associated with these instruments is recorded in current earnings.
Production and Operating Costs Reporting
      We strive to increase our production levels to maximize our revenue and cash available for distribution. Additionally, we continuously monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we continuously monitor our production and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold.
      Such costs include, but are not limited to, the cost of electricity to lift produced fluids, chemicals to treat wells, field personnel to monitor the wells, well repair expenses to restore production, and well workover expenses intended to increase production. We incur and separately report severance and ad valorem taxes paid to the states and counties in which our properties are located. These taxes are reported as production taxes and are a percentage of oil and natural gas revenue in the case of severance taxes and a percentage of property valuation in the case of ad valorem taxes. Gathering and transportation costs are generally borne by the purchasers of our oil and natural gas as the price paid for our products reflects these costs.

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Operating Data
      The following table sets forth selected financial and operating data of Legacy for the periods indicated.
                                             
        Nine Months Ended
    Year Ended December 31,   September 30,
         
    2003   2004   2005   2005(a)   2006
                     
                (Unaudited)
Revenues (In thousands):
                                        
 
Oil sales
   $ 7,919     $ 10,998     $ 18,225     $ 11,419     $ 32,444  
 
Natural gas sales
     3,697       3,945       7,318       3,872       10,822  
 
Realized gain (loss) on oil swaps
     (444 )     46       (3,531 )     (3,531 )     (6,898 )
 
Realized gain (loss) on natural gas swaps
     (179 )     (120 )     —       —       4,717  
 
Unrealized gain (loss) on oil swaps
     450       (679 )     (911 )     (2,855 )     1,342  
 
Unrealized gain (loss) on natural gas swaps
     (110 )     120       (1,717 )     (1,263 )     6,373  
                               
   
Total revenue
   $ 11,333     $ 14,310     $ 19,384     $ 7,642     $ 48,800  
                               
Expenses (In thousands):
                                        
 
Oil and natural gas production
   $ 3,496     $ 4,345     $ 6,376     $ 3,610     $ 10,160  
 
Production and other taxes
   $ 661     $ 928     $ 1,636     $ 1,140     $ 2,710  
 
General and administrative
   $ 543     $ 731     $ 1,354     $ 439     $ 3,265  
 
Depletion, depreciation, amortization and accretion
   $ 766     $ 883     $ 2,291     $ 736     $ 12,702  
Production:
                                        
 
Oil (MBbl)
     279       286       354       232       516  
 
Natural gas (MMcf)
     848       783       1,027       631       1,599  
 
Total (MBoe)
     420       416       525       337       782  
 
Average daily production (Boe per day)
     1,152       1,138       1,438       1,236       2,864  
Average Sale Prices (including hedges)(c):
                                        
 
Oil (per Bbl)
   $ 28.40     $ 36.24     $ 38.94 (d)   $ 21.69 (d)   $ 52.11 (e)
 
Natural gas (per Mcf)
   $ 4.02     $ 5.04     $ 5.45     $ 4.13     $ 13.70  
 
Combined (per Boe)
   $ 26.98     $ 34.40     $ 36.92 (d)   $ 22.68 (d)   $ 62.40 (e)
Average Sale Prices (including realized hedge gains/losses)(f):
                                        
 
Oil (per Bbl)
   $ 26.79     $ 38.61     $ 41.51 (d)   $ 34.00 (d)   $ 49.51 (e)
 
Natural gas (per Mcf)
   $ 4.15     $ 4.89     $ 7.13     $ 6.14     $ 9.72  
 
Combined (per Boe)
   $ 26.17     $ 35.74     $ 41.93 (d)   $ 34.90 (d)   $ 52.54 (e)
Average Sale Prices (excluding hedges):
                                        
 
Oil (per Bbl)
   $ 28.38     $ 38.45     $ 51.48     $ 49.22     $ 62.88  
 
Natural gas (per Mcf)
   $ 4.36     $ 5.04     $ 7.13     $ 6.14     $ 6.77  
 
Combined (per Boe)
   $ 27.66     $ 35.92     $ 48.65     $ 45.37     $ 55.33  
Average unit costs per Boe:
                                        
 
Oil and natural gas production expenses
   $ 8.32     $ 10.44     $ 12.14     $ 10.71     $ 12.99  
 
Production taxes
   $ 1.57     $ 2.23     $ 3.12     $ 3.38     $ 3.47  
 
General and administrative expenses
   $ 1.29     $ 1.76     $ 2.58     $ 1.30     $ 4.18  
 
Depletion, depreciation, amortization and accretion
   $ 1.82     $ 2.12     $ 4.36     $ 2.18     $ 16.24  
 
(a) Reflects MBN Properties LP’s purchase of the PITCO properties on September 14, 2005. Consequently, the operations of the PITCO properties are only included for the period following the date of acquisition.
 
(b) Reflects Legacy’s purchase of the oil and natural gas properties acquired in the March 15, 2006 formation transactions and the South Justis, Farmer Field and Kinder Morgan acquisitions. Consequently, the

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operations of these acquired properties are only included for the period from the closing dates of such acquisitions through September 30, 2006.
 
(c) Includes both the realized and unrealized hedge gains and losses from Legacy’s oil and natural gas swaps. Since Legacy does not specifically designate its commodity derivative instruments as cash flow hedges, current earnings reflect a mark-to-market adjustment for these instruments. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods. See Note 10 on page F-35 for details regarding Legacy’s unrealized gains and losses.
 
(d) Includes the effects of approximately $2.0 million for the year ended December 31, 2005 of derivative premiums to cancel and reset 2006 oil swaps from $51.31 to $59.38 per Bbl and approximately $0.8 million of premiums paid on July 22, 2005 for an option to enter into a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised.
 
(e) Includes the effect of approximately $4.0 million of derivative premiums to cancel and reset 2007 oil swaps from $60.00 to $65.82 per barrel for 372,000 barrels and for 2008 oil swaps from $60.50 to $66.44 per barrel for 348,000 barrels, which reflected the prevailing oil swap market at the time of the reset.
 
(f) Includes only the realized hedge gains (losses) from Legacy’s oil and natural gas swaps.

Results of Operations
Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005
      Legacy’s revenues from the sale of oil were $32.4 million for the nine months ended September 30, 2006 and $11.4 million for the nine months ended September 30, 2005. Legacy’s revenues from the sale of natural gas were $10.8 million for the nine months ended September 30, 2006 and $3.9 million for the nine months ended September 30, 2005. The $21.0 million increase in oil revenues reflects an increase in oil production of 284 MBbls (122%) due primarily to Legacy’s purchase of the oil and natural gas properties acquired in the March 15, 2006 formation transactions, or the Legacy Formation, the PITCO acquisition and the South Justis, Farmer Field and Kinder Morgan acquisitions while the realized price excluding the effects of hedging increased $13.66 per Bbl. The $6.9 million increase in natural gas revenues reflects an increase in natural gas production of approximately 968 MMcf (153%) due primarily to both the Legacy Formation and the PITCO acquisition while the realized price per Mcf excluding the effects of hedging increased $0.63 per Mcf. Since the Legacy Formation occurred on March 15, 2006, Legacy’s revenues and related volumes for the nine months ended September 30, 2006 do not reflect the 50 MBbls and 119 MMcf produced by the oil and natural gas properties acquired in that transaction from January 1, 2006 to March 15, 2006. For the nine months ended September 30, 2006, Legacy recorded $5.5 million of net gains on oil and natural gas swaps comprised of realized losses of $2.2 million from net cash settlements of oil and natural gas swap contracts and net unrealized gains of $7.7 million. Legacy had unrealized net gains from its oil swaps because the fixed price of its oil swap contracts were above the NYMEX index prices at September 30, 2006. As a point of reference, the NYMEX price for light sweet crude oil for the near-month close at September 30, 2006 was $62.91 per Bbl, a price which is less than the average contract prices of Legacy’s outstanding oil swap contracts. Legacy had unrealized net gains from its natural gas swaps because the fixed prices of its natural gas swap contracts were above the NYMEX index prices at September 30, 2006. As a point of reference, the NYMEX price for natural gas for the near-month close at September 30, 2006 was $5.62 per MMbtu, a price which is less than the average contract prices of Legacy’s outstanding natural gas swap contracts. For the nine months ended September 30, 2005, Legacy recorded $6.4 million of net losses on oil swaps comprised of a realized loss of $3.5 million from net cash settlements of oil swap contracts and a net unrealized loss of $2.9 million. For the nine months ended September 30, 2005, Legacy recorded $1.3 million of net losses on gas swaps from a net unrealized loss. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods.
      Legacy’s oil and natural gas production expenses, excluding production and other taxes, increased to $10.2 million for the nine months ended September 30, 2006, from $3.6 million for the nine months ended September 30, 2005. Production expenses increased primarily because of (i) $1.8 million related to the PITCO acquisition, (ii) $2.6 million related to the Legacy Formation, (iii) $0.6 million related to the South

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Justis, Farmer Field and Kinder Morgan acquisitions and (iv) increased production and increased cost of services and certain operating costs that are directly related to higher commodity prices, particularly the cost of electricity, which powers artificial lift equipment and pumps involved in the production of oil.
      Legacy’s production and other taxes were $2.7 million and $1.1 million for the nine months ended September 30, 2006 and 2005, respectively. Production and other taxes increased primarily because of (i) approximately $0.5 million of taxes related to the PITCO Acquisition, (ii) $0.6 million of taxes related to the Legacy Formation and (iii) higher commodity prices in the 2006 period.
      Legacy’s general and administrative expenses were $3.3 million and $0.4 million for the nine months ended September 30, 2006 and 2005, respectively. General and administrative expenses increased approximately $2.9 million between periods primarily due to increased employee costs related to business expansion and approximately $250,000 of costs incurred in connection with our private equity offering.
      Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $12.7 million and $0.7 million for the nine months ended September 30, 2006 and 2005, respectively, reflecting primarily $5.0 million of DD&A related to the PITCO acquisition, $5.6 million to the Legacy Formation and $0.4 million to recent acquisitions.
      Impairment expense was $8.6 million for the nine months ended September 30, 2006 involving 22 separate producing fields, due primarily to the decline in natural gas prices from the dates at which the purchase prices for the PITCO acquisition and the Legacy Formation were allocated among the purchased properties. As a point of reference, the NYMEX closing price for natural gas was $5.62 per MMbtu at September 30, 2006, as compared to $7.21 per MMbtu on March 31, 2006 at the time of the Legacy Formation and $9.72 per MMbtu on September 30, 2005 at the time of the PITCO acquisition.
      Legacy recorded interest income of $93,659 for the nine months ended September 30, 2006 and $153,423 for the nine months ended September 30, 2005. The decrease of $59,764 is a result of lower average cash balances for the current period.
      Interest expense was $4.5 million and $0.3 million for the nine months ended September 30, 2006 and 2005, respectively, reflecting higher average borrowings and higher average interest rates in the current period. Legacy borrowed $75.5 million to fund the PITCO acquisition and $65.8 million under its new revolving credit facility at the close of the Legacy Formation.
      Legacy recorded equity in loss of partnership of $317,788 and $337,949 for the nine months ended September 30, 2006 and 2005, respectively. In both periods, Legacy recorded equity in loss of partnership related to its investment in MBN Management, LLC, which was formed in July, 2005. Legacy did not acquire any interest in MBN Management, LLC as part of the Legacy Formation. Accordingly, such losses will not be incurred in the future.
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
      Legacy’s revenues from the sale of oil were $18.2 million for the year ended December 31, 2005 and $11.0 million for the year ended December 31, 2004. Revenues from the sale of natural gas were $7.3 million for the year ended December 31, 2005 and $3.9 million for the year ended December 31, 2004. The $7.2 million increase in oil revenues reflects an increase in oil production of 67.9 MBbls (24%) due primarily to the PITCO acquisition while the realized price excluding the effects of hedging increased $13.05 per Bbl. The $3.4 million increase in natural gas revenues reflects an increase in natural gas production of approximately 244 MMcf (31%) due primarily to the PITCO acquisition while the realized price per Mcf excluding the effects of hedging increased $2.09 per Mcf. For the year ended December 31, 2005, Legacy recorded $6.2 million of losses on oil and natural gas swaps comprised of a realized loss of $3.5 million and unrealized losses of $2.6 million, as compared to a realized loss of $73,830 for the year ended December 31, 2004 and an unrealized loss of $558,953. Unrealized losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods. The realized loss of $3.5 million included a $2.0 million loss incurred in June 2005 when Legacy cancelled its existing oil swap contracts which involved fixed prices of approximately $51.31 per Bbl and entered into new oil swaps at

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fixed prices of $59.38 per Bbl, and includes a premium of $819,000 for an option to enter into a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised.
      Legacy’s oil and natural gas production expenses, excluding production and other taxes, increased to $6.4 million for the year ended December 31, 2005, from $4.3 million for the year ended December 31, 2004. Production expenses increased primarily because of (i) $1.6 million of expenses related to the PITCO acquisition and (ii) increased production and increased cost of services and certain operating costs that are directly related to higher commodity prices, particularly the cost of electricity, which powers artificial lift equipment and pumps involved in the production of oil.
      Legacy’s production and other taxes were $1.6 million and $927,657 for the years ended December 31, 2005 and 2004, respectively. Production and other taxes increased primarily because of (i) approximately $400,000 of taxes related to the PITCO Acquisition and (ii) increased production and increased oil and natural gas prices which is the basis on which severance taxes are paid (percentage of revenue) while ad valorem or property taxes are based on property values, which increase directly with higher oil and natural gas prices.
      Legacy’s general and administrative expenses were $1.35 million and $731,200 for the years ended December 31, 2005 and 2004, respectively. General and administrative expenses increased approximately $623,200 between periods primarily due to increased employee costs related to business expansion and costs incurred in connection with our private equity offering.
      Legacy’s depletion, depreciation, amortization and accretion expense, or DD&A, was $2.3 million and $883,457 for the years ended December 31, 2005 and 2004, respectively, reflecting primarily $1.6 million of DD&A related to the PITCO Acquisition.
      Legacy recorded interest income of $185,308 for the year ended December 31, 2005 and $419,257 for the year ended December 31, 2004. The decrease of $233,949 is a direct result of lower average cash balances for the current period.
      Interest expense was $1.58 million and $213,711 for the years ended December 31, 2005 and 2004, respectively, reflecting higher average borrowings and higher average interest rates in the current period.
      No gain on sale of partnership investment was recorded for the year ended December 31, 2005. Legacy realized a gain on sale of partnership investment of $1.3 million for the year ended December 31, 2004 related to the sale of the Accord partnership.
      Legacy recorded equity in loss of partnerships of $495,295 for the year ended December 31, 2005 and a gain of $183,474 for the year ended December 31, 2004. The decrease in partnership income is a result of the sale of the Accord partnership interest in April 2004. Legacy recorded equity in loss of partnership of $495,295 related to its investment in MBN Management, LLC, which includes the Moriah Group’s 58.36% share of 100% of the MBN Management, LLC loss since the Founding Investors have reported 100% of this loss.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
      Legacy’s revenues from the sale of oil were $11.0 million and $7.9 million for the years ended December 31, 2004 and 2003, respectively. Legacy’s revenues from the sale of natural gas were $3.9 million and $3.7 million for the years ended December 31, 2004 and 2003, respectively. The $3.1 million increase in oil revenues reflects an increase in oil production of approximately 7.0 MBbls (2%) while the realized price excluding the effects of hedging increased $10.07 per Bbl. The $248,443 increase in natural gas revenues reflects a decrease in natural gas production of approximately 65 MMcf (8%) while the realized price excluding the effects of hedging increased $0.68 per Mcf. For the year ended December 31, 2004, Legacy recorded $632,783 of losses on oil and natural gas swaps comprised of realized losses of $73,830 and of unrealized losses of $558,953, as compared to net hedge losses of $282,872 comprised of an unrealized gain of $340,179 and a realized loss of $623,051 for the year ended December 31, 2003.

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      Legacy’s oil and natural gas production expenses, excluding production and other taxes, were $4.3 million and $3.5 million for 2004 and 2003, respectively. Production expenses increased primarily because of increased cost of services and certain costs that are directly related to higher commodity prices, particularly the cost of electricity, which powers artificial lift equipment and pumps involved in the production of oil.
      Legacy’s production and other taxes were $927,657 and $661,563 for 2004 and 2003, respectively. Production and other taxes increased because of increased oil and natural gas prices which is the basis on which severance taxes are paid (percentage of revenue) while ad valorem or property taxes are based on property values, which increase directly with higher oil and natural gas prices.
      Legacy’s general and administrative expenses were $731,200 and $543,221 for 2004 and 2003, respectively. General and administrative expenses increased $187,979 between periods due to business expansion.
      Legacy had $822 of dry hole cost for the year ended December 31, 2004 and $1.5 million for the year ended December 31, 2003. The reduction in dry hole expense was a result of the Moriah Group’s decision to eliminate exploratory activities during 2004.
      Legacy’s DD&A was $883,457 and $765,620 for 2004 and 2003, respectively, reflecting higher levels of capital spending in the prior period, adding to the depreciable book basis in 2004 from 2003 activity.
      Legacy had no impairment expense for the year ended December 31, 2004 and $471,394 for the year ended December 31, 2003. The impairment expense in 2003 related to prospect costs related to an exploratory dry hole drilled in 2003.
      Legacy recorded interest income of $419,257 for the year ended December 31, 2004 and $56,390 for the year ended December 31, 2003. The increase of $362,867 is a direct result of higher average cash balances and higher interest rates received on invested funds.
      Legacy’s interest expense was $213,711 and $94,284 for 2004 and 2003, respectively. The $119,427 increase was due to higher interest rates and higher average outstanding borrowings during 2004 as compared to 2003.
      Legacy realized gain on sale of partnership investment of $1.3 million in 2004 as the result of the sale of the Accord partnership interest in April 2004. For the year ended December 31, 2003, Legacy recorded no gain or loss on sale of partnership investment.
      Legacy recorded equity in income of partnership of $183,474 for the year ended December 31, 2004 and $311,367 for the year ended December 31, 2003. The decrease in partnership income is a result of the sale of the Accord partnership interest in April 2004.
Capital Resources and Liquidity
      Legacy’s primary sources of capital and liquidity have been proceeds from bank borrowings and cash flow from operations. To date, Legacy’s primary use of capital has been for the acquisition and exploitation of oil and natural gas properties. During the nine months ended September 30, 2006, Legacy cancelled (before their original settlement date) a portion of its NYMEX oil swaps covering periods in 2007 and 2008 and realized a loss of $4.0 million. As a result, Legacy’s working capital was reduced by $4.0 million at September 30, 2006. During the year ended December 31, 2005, Legacy cancelled (before their original settlement date) a portion of its NYMEX WTI oil swaps covering periods in 2006 and realized a loss of $2.0 million. Legacy, through its ownership of MBN Properties LP, paid a $0.8 million premium for an option to enter into a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised. As a result, Legacy’s working capital was reduced by $2.8 million at December 31, 2005.
      As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations and planned capital expenditures. Our future success in growing reserves and production will be highly dependent on capital resources available to us and our success in acquiring and exploiting

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additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we would need to borrow additional amounts under our credit facility, if available, or obtain additional debt or equity financing. Our credit facility will impose certain restrictions on our ability to obtain additional debt financing. Based upon current oil and natural gas price expectations for the year ending December 31, 2007, we anticipate that our cash on hand, cash flow from operations and available borrowing capacity under our credit facility will provide us sufficient working capital to meet our planned capital expenditures of $10.3 million and planned cash distributions of $40.1 million for the year ending December 31, 2007. Please read “— Financing Activities — Our Revolving Credit Facility.”
Cash Flow from Operations
      Legacy’s net cash provided by operating activities was $21.8 million and $10.1 million for the nine months ended September 30, 2006 and 2005, respectively, with the 2006 period being favorably impacted by higher realized oil and natural gas prices, partially offset by lower sales volumes and higher expenses.
      Legacy’s net cash provided by operating activities was $14.4 million and $8.6 million for the years ended December 31, 2005 and 2004, respectively. The increase in net cash provided by operating activities during the year ended December 31, 2005 was due to higher oil and natural gas prices and increased oil and natural gas volumes for that period, partially offset by increased expenses, as discussed above in “Results of Operations.”
      Legacy’s net cash provided by operating activities was $8.6 million and $6.8 million for the years ended 2004 and 2003, respectively. The increase in net cash provided by operating activities in 2004 was partially due to increased revenues from higher oil and natural gas prices and increased oil volumes, partially offset by lower natural gas volumes and increased expenses, as discussed above in “Results of Operations.”
      Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on our ability to maintain and increase production through acquisitions and exploitation projects, as well as the prices of oil and natural gas.
      We enter into hedging arrangements to reduce the impact of oil and natural gas price volatility on our operations. Currently, we use swaps to hedge NYMEX oil and natural gas prices, which do not include the additional net discount that we typically realize in the Permian Basin. At December 31, 2005, we had in place oil and natural gas swaps covering significant portions of our estimated 2006 through 2010 oil and natural gas production. We have hedged approximately 85% of our expected 2006 production. We have also hedged approximately 63% of our currently expected oil and natural gas production for 2007 through 2010 from existing total proved reserves.
      By removing the price volatility from a significant portion of our oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers.

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      The following tables summarize, for the periods indicated, our oil and natural gas swaps currently in place through December 31, 2010. We use swaps as our mechanism for hedging commodity prices whereby we pay the counterparty floating prices and receive fixed prices from the counterparty, which serves to hedge the floating prices we are paid by purchasers of our oil and natural gas. These transactions are settled based upon the NYMEX price of oil at Cushing, Oklahoma, and NYMEX price of natural gas at Henry Hub on the average of the three final trading days of the month and settlement occurs on the fifth day of the production month.
                         
    Annual        
    Volumes   Average   Price
Calendar Year   (Bbls)   Price per Bbl   Range per Bbl
             
2006
     340,952     $ 62.18     $ 59.38 - $68.00  
2007
     671,637     $ 67.62     $ 64.15 - $75.70  
2008
     618,689     $ 67.11     $ 62.25 - $73.45  
2009
     571,453     $ 64.46     $ 61.05 - $71.40  
2010
     426,687     $ 61.51     $ 60.15 - $61.90  
                         
    Annual        
    Volumes   Average   Price
Calendar Year   (Mcf)   Price per Mcf   Range per Mcf
             
2006
     862,441     $ 10.46     $ 9.45 - $11.56  
2007
     1,558,504     $ 9.56     $ 9.02 - $11.83  
2008
     1,422,732     $ 8.61     $ 7.98 - $10.58  
2009
     1,316,354     $ 8.38     $ 7.77 - $10.18  
2010
     1,218,899     $ 7.99     $ 7.37 - $ 9.73  
      In July 2006, we entered into basis swaps to receive floating NYMEX prices less a fixed basis differential and pay prices based on the floating Waha index, a natural gas hub in West Texas. The prices that we receive for our natural gas sales follow Waha more closely than NYMEX. The basis swaps thereby provide a better match between our natural gas sales and the settlement payments on our natural gas swaps. The following table summarizes, for the periods indicated, our NYMEX basis swaps currently in place through December 31, 2010.
                 
    Annual    
    Volumes   Basis
Calendar Year   (Mcf)   per Mcf
         
2006
     429,000     $ (0.99) - $(1.15)  
2007
     1,560,000     $ (0.88)  
2008
     1,422,000     $ (0.84)  
2009
     1,320,000     $ (0.68)  
2010
     1,200,000     $ (0.57)  
Investing Activities — Acquisitions and Capital Expenditures
      Legacy’s capital expenditures were $45.4 million for the nine months ended September 30, 2006. The total includes $7.7 million paid to three charitable foundations in the Legacy Formation for oil and natural gas properties, $8.8 million, $5.8 million and $17.3 million for the purchase of producing oil and natural gas properties in the South Justis Unit from Henry Holding LP, the Farmer Field from Larron Oil Corporation and various oil and natural gas properties from Kinder Morgan, respectively, and $7.0 million of capitalized operating rights related to the South Justis Unit. Legacy also paid $2.0 million as a deposit on the acquisition of oil and natural gas properties from Kinder Morgan which closed July 31, 2006.
      Legacy’s capital expenditures were $66.9 million and $3.3 million for the years ended December 31, 2005 and 2004, respectively. The total for the year ended December 31, 2005 includes $63.9 million in cash ($64.3 million, inclusive of asset retirement obligations) for the acquisition of producing oil and natural gas

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properties from PITCO and $1.9 million for exploitation projects. The total for the year ended December 31, 2004 includes $1.6 million for acquisitions and $1.7 million for exploitation projects and of producing properties. The PITCO acquisition was made in anticipation of the formation of Legacy Reserves LP.
      Legacy’s capital expenditures were $3.3 million for the year ended December 31, 2004 and $4.0 million for the year ended December 31, 2003. The total for 2004 includes $1.6 million for acquisitions and $1.7 million for exploitation projects. The total for 2003 includes $2.4 million for acquisitions and $1.6 million for exploitation projects.
      During the year ended December 31, 2005, Legacy cancelled (before their original settlement date) a portion of the hedges and realized a loss of $2.0 million, all of which related to canceling and replacing 2006 oil swaps. Legacy, through its ownership of MBN Properties LP, paid a $0.8 million premium for an option to enter a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised.
      We currently anticipate that our drilling budget, which predominantly consists of drilling, recompletion and refracture stimulation projects and one tertiary (CO2 ) recovery project will be $10.3 million for the year ending December 31, 2007. Our borrowing capacity under our revolving credit facility is $23.2 million as of September 30, 2006. The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based upon current oil and natural gas price expectations for the year ending December 31, 2007, we anticipate that we will have sufficient sources of working capital, including our cash flow from operations and available borrowing capacity under our credit facility, to meet our cash obligations including our planned capital expenditures of $10.3 million and planned cash distributions of $30.3 million for the year ending December 31, 2007. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.
Financing Activities
Moriah Group Credit Agreement
      On July 29, 1999, the Moriah Group entered into a Credit Agreement secured by substantially all of its oil and natural gas assets that permitted borrowings up to the lesser of the borrowing base, or $20 million. The agreement provided for certain restrictions including, but not limited to, limitations on additional borrowings, restrictions on use of proceeds, sales of collateral, and distribution to owners. It also required the maintenance of certain quarterly debt ratios. This Credit Agreement was replaced by the Moriah Group Senior Credit Facility described below. There was no outstanding balance since the borrowings under this credit agreement had been repaid in full in August 2005.
Moriah Group Senior Credit Facility
      On September 13, 2005, the Moriah Group replaced its Credit Agreement with a Senior Credit Facility with a new lending group that permitted borrowings in the lesser amount of (i) the borrowing base (initially set at $40 million) or (ii) $75 million. Interest on the Senior Credit Facility was payable in accordance with the LIBOR period selected by the Moriah Group at the applicable LIBOR period rate plus 1.5% to 2.0%, or the applicable base rate (ABR) up to a maximum of ABR plus 0.50%, dependent on the percentage of the borrowing base which is drawn. Legacy Reserves LP replaced the Moriah Group Senior Credit Facility concurrently with the closing of our private equity offering with the credit facility described below and repaid the remaining outstanding amount of approximately $18.0 million in full.

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Moriah Group Notes Advanced to MBN Properties LP and MBN Management, LLC
      MBN Properties LP and MBN Management, LLC, a Delaware limited liability company, (collectively the “MBN Group”) were formed to acquire oil and natural gas producing properties from PITCO in partnership with Brothers Production Properties, Ltd., and certain third party minority investors. On July 22, 2005, Moriah Properties, Ltd. entered into a $6.5 million subordinated loan agreement with MBN Properties LP. MBN Properties LP borrowed approximately $1.65 million to fund the deposit for the purchase of the PITCO properties.
      Also on July 22, 2006, MBN Management, LLC borrowed approximately $0.7 million under a $2 million subordinated loan agreement to fund expenses.
      On September 13, 2005, the Moriah Group entered into a $34.0 million subordinated loan agreement with MBN Properties LP as the borrower which replaced the $6.5 million Moriah loan agreement. On September 14, 2005, MBN Properties LP borrowed an additional $17.6 million to fund the remaining purchase price for the PITCO properties.
      On March 15, 2006 with proceeds from our private equity offering and borrowings under our new credit facility described below, each of MBN Properties LP and MBN Management LLC fully repaid their subordinated debt in the amounts, including accrued interest, of $20.5 million and $0.9 million, respectively.
Our Revolving Credit Facility
      At the closing of our private equity offering, we entered into a new, four-year, $300 million revolving credit facility with BNP Paribas as administrative agent. Our obligations under the credit facility are secured by mortgages on more than 80% of our oil and gas properties as well as a pledge of all of our ownership interests in our operating subsidiaries. The amount available for borrowing at any one time is limited to the borrowing base, which was initially set at $130 million. The borrowing base is subject to semi-annual redeterminations on April 1 and October 1 of each year. Additionally, either us or the lenders may, once during each calendar year, elect to redetermine the borrowing base between scheduled redeterminations. We also have the right, once during each calendar year, to redetermine the borrowing base upon the proposed acquisition of certain oil and gas properties where the purchase price is greater than 10% of the borrowing base. Any increase in the borrowing base requires the consent of all the lenders and any decrease in the borrowing base must be approved by the lenders holding 662/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the credit facility. If the required lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 662/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the credit facility so long as it does not increase the borrowing base then in effect. Outstanding borrowings in excess of the borrowing base must be prepaid, and, if mortgaged properties represent less than 80% of total value of oil and gas properties evaluated in the most recent reserve report, we must pledge other oil and natural gas properties as additional collateral.
      We may elect that borrowings be comprised entirely of alternate base rate (ABR) loans or Eurodollar loans. Interest on the loans is determined as follows:
  •  with respect to ABR Loans, the alternate base rate equals the higher of the prime rate or the Federal funds effective rate plus 0.50%, plus an applicable margin between 0% and 0.375%, or
 
  •  with respect to any Eurodollar loans for any interest period, the London interbank rate, or LIBOR plus an applicable margin between 1.25% and 1.875% per annum.
      Interest is generally payable quarterly for ABR loans and on the last day of the applicable interest period for any Eurodollar loans.

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      Our revolving credit facility also contains various covenants that limit our ability to:
  •  incur indebtedness;
 
  •  enter into certain leases;
 
  •  grant certain liens;
 
  •  enter into certain swaps;
 
  •  make certain loans, acquisitions, capital expenditures and investments;
 
  •  make distributions other than from available cash;
 
  •  merge, consolidate or allow any material change in the character of its business; or
 
  •  engage in certain asset dispositions, including a sale of all or substantially all of our assets.
      Our credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:
  •  consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization and other similar charges excluding unrealized gains and losses under SFAS No. 133, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0; and
 
  •  consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under SFAS No. 133, which includes the current portion of oil, natural gas and interest rate swaps.
      If an event of default exists under our revolving credit facility, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following would be an event of default:
  •  failure to pay any principal when due or any reimbursement amount, interest, fees or other amount within certain grace periods;
 
  •  a representation or warranty is proven to be incorrect when made;
 
  •  failure to perform or otherwise comply with the covenants or conditions contained in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;
 
  •  default by us on the payment of any other indebtedness in excess of $1.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;
 
  •  bankruptcy or insolvency events involving us or any of our subsidiaries;
 
  •  the loan documents cease to be in full force and effect our failing to create a valid lien, except in limited circumstances;
 
  •  a change of control, which will occur upon (i) the acquisition by any person or group of persons of beneficial ownership of more than 35% of the aggregate ordinary voting power of our equity securities, (ii) the first day on which a majority of the members of the board of directors of our general partner are not continuing directors (which is generally defined to mean members of our board of directors as of the closing of this offering and persons who are nominated for election or elected to our general partner’s board of directors with the approval of a majority of the continuing directors who were members of such board of directors at the time of such nomination or election), (iii) the direct or indirect sale, transfer or other disposition in one or a series of related transactions of all or substantially all of the properties or assets (including equity interests of subsidiaries) of us and our subsidiaries to any person, (iv) the adoption of a plan related to our liquidation or dissolution or (v) Legacy Reserves GP, LLC ceasing to be our sole general partner.

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  •  the entry of, and failure to pay, one or more adverse judgments in excess of $1.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal; and
 
  •  specified ERISA events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $1,000,000 in any year.
Contractual Obligations
      A summary of our contractual obligations as of December 31, 2005 is provided in the following table.
                                         
    Obligations Due in Period
     
Contractual Cash Obligations   2006   2007-2008   2009-2010   Thereafter   Total
                     
Long-term debt
   $ —     $ —     $ 67,800,000     $ —     $ 67,800,000  
Interest on long-term debt (a)
     4,651,080       9,302,160       5,620,055       —       19,573,295  
Commodity derivatives
     351,403       3,896,399       505,430       —       4,753,232  
Management compensation (b)
     915,000       1,830,000       1,830,000       —       4,575,000  
Office Lease
     82,056       102,570       —       —       184,626  
                               
Total contractual cash obligations
   $ 5,999,539     $ 15,131,129     $ 75,755,485     $ —     $ 96,886,153  
                               
 
(a) Based upon an initial effective interest rate of 6.86% under our revolving credit facility.
 
(b) Does not include any liability associated with management compensation subsequent to the 2009-2010 period as there is no estimated termination date of the employment agreements.
      A summary of our contractual obligations as of September 30, 2006 is provided in the following table.
                                         
    Obligations Due in Period
     
Contractual Cash Obligations   2006   2007-2008   2009-2010   Thereafter   Total
                     
Long-term debt
   $ —     $ —     $ 106,800,000     $ —     $ 106,800,000  
Interest on long-term debt (a)
     1,925,070       15,400,560       1,604,225       —       18,929,855  
Commodity derivatives
     (1,646,716 )     (1,788,119 )     2,174,372       —       (1,260,463 )
Management compensation (b)
     457,500       1,830,000       1,830,000       —       4,117,500  
Office Lease
     27,513       225,070       233,333       93,333       579,249  
                               
Total contractual cash obligations
   $ 763,367     $ 15,667,511     $ 112,641,930     $ 93,333     $ 129,166,141  
                               
 
(a) Based upon our interest rate of 7.21% under our revolving credit facility as of September 30, 2006.
 
(b) Does not include any liability associated with management compensation subsequent to the 2009-2010 period as there is no estimated termination date of the employment agreements.
Critical Accounting Policies and Estimates
      The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Estimates and assumptions are evaluated on a regular basis. Legacy based its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent

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from other sources. Actual results may differ from these estimates and assumptions used in preparation of the financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:
  •  it requires assumptions to be made that were uncertain at the time the estimate was made, and
 
  •  changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.
Please read Note 1 of the Notes to the Consolidated Financial Statements for a detailed discussion of all significant accounting policies that we employ and related estimates made by management.
      Nature of Critical Estimate Item: Oil and Natural Gas Reserves — Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. LaRoche Petroleum Consultants, Ltd., prepares a reserve and economic evaluation of all our properties in accordance with SEC guidelines on a lease, unit or well-by-well basis, depending on the availability of well-level production data. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the economics of producing the reserves may change and therefore the estimate of proved reserves also may change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion rates are made concurrently with changes to reserve estimates.
      Assumptions/ Approach Used: Units-of-production method to deplete our oil and natural gas properties — The quantity of reserves could significantly impact our depletion expense. Any reduction in proved reserves without a corresponding reduction in capitalized costs will increase the depletion rate.
      Effect if Different Assumptions Used: Units-of-production method to deplete our oil and natural gas properties — A 10% increase or decrease in reserves would have decreased or increased, respectively, our depletion expense for the six months ended June 30, 2006 by approximately 10%.
      Nature of Critical Estimate Item: Asset Retirement Obligations — We have certain obligations to remove tangible equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Prior to January 1, 2003, the costs associated with this activity were charged to expense. We adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations effective January 1, 2003. SFAS No. 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets (“asset retirement obligations” or “ARO”). Primarily, SFAS No. 143 requires us to estimate asset retirement costs for all of our assets, adjust those costs for inflation to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an ARO liability in that amount with a corresponding addition to our asset value. When new obligations are incurred, i.e. a new well is drilled or acquired, we add a layer to the ARO liability. We then accrete the liability layers quarterly using the applicable period-end effective credit-adjusted-risk-free rates for each layer. Should either the estimated life or the estimated abandonment costs of a property change materially upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost. Thus, abandonment costs will almost always

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approximate the estimate. When well obligations are relieved by sale of the property or plugging and abandoning the well, the related liability and asset costs are removed from our balance sheet.
      Assumptions/ Approach Used: Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.
      Effect if Different Assumptions Used: Since there are so many variables in estimating AROs, we attempt to limit the impact of management’s judgment on certain of these variables by developing a standard cost estimate based on historical costs and industry quotes updated annually. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of a discount factor and some significant calculations, could differ from actual results, despite our efforts to make an accurate estimate. We engage independent engineering firms to evaluate our properties annually. We use the remaining estimated useful life from the year-end reserve report by our independent reserve engineers in estimating when abandonment could be expected for each property. We expect to see our calculations impacted significantly if interest rates continue to rise, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis.
      Nature of Critical Estimate Item: Derivative Instruments and Hedging Activities — We periodically use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Currently, these transactions are swaps whereby we exchange our floating price for our oil and natural gas for a fixed price with qualified and creditworthy counterparties (currently BNP Paribas and Bank of America). Our existing oil and natural gas swaps are with members of our lending group which enables us to avoid margin calls for out-of-the money mark-to-market positions.
      We do not specifically designate derivative instruments as cash flow hedges, even though they reduce our exposure to changes in oil and natural gas prices. Therefore, the mark-to-market of these instruments is recorded in current earnings. While we are not internally preparing an estimate of the current market value of these derivative instruments, we use market value statements from each of our counterparties as the basis for these end-of-period mark-to-market adjustments. When we record a mark-to-mark adjustment resulting in a loss in a current period, these unrealized losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future period. As shown in the tables above, we have hedged a significant portion of our future production through 2010. Taking into account the mark-to-market liabilities and assets recorded as of June 30, 2006, the future cash obligations table presented above shows the amounts which we would expect to pay the counterparties over the time periods shown. As oil and gas prices rise and fall, our future cash obligations related to these derivatives will rise and fall.
Consolidation of Variable Interest Entity
      FASB Interpretation (FIN) No. 46 (revised December 2003) — Consolidation of Variable Interest Entities, addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and, accordingly, should consolidate the entity. Through March 15, 2006 MBN Properties LP was a variable interest entity since MBN Properties LP required additional subordinated financial support to commence its activities. Legacy consolidated MBN Properties LP as a variable interest entity under FASB FIN 46R because it was the primary beneficiary of MBN Properties LP under the expected losses test of paragraph 14 of FIN 46R. While MBN Management, LLC is a variable interest entity, through March 15, 2006 it was accounted for by Legacy utilizing the equity method since no entity was the primary beneficiary. Legacy’s non-controlling income of $538 for the year ended

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December 31, 2005 represents the loss of MBN Properties LP attributable to the other owners’ equity interests. As we have acquired all of MBN Properties LP’s properties in the formation transactions on March 15, 2006, after that date there are no remaining non-controlling interests.
Recently Issued Accounting Pronouncements
      Emerging Issues Task Force (“EITF”) Issue 04-9 and Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) FAS 19-1: Statement of Financial Accounting Standards (“FAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” requires the cost of drilling an exploratory well to be capitalized pending determination of whether the well has found proved reserves. If this determination cannot be made at the conclusion of drilling, FAS No. 19 sets out additional requirements for continuing to carry the cost of the well as an asset. These requirements include firm plans for further drilling and a one-year time limitation on continued capitalization in certain instances. In April 2005, the FASB issued FSP FAS 19-1, which was adopted effective January 1, 2005. This FSP amends FAS No. 19 to allow continued capitalization when (i) the well has found a sufficient quantity of reserves to justify proceeding with the project plan and (ii) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project which may include more than one exploratory well if the reserves are intended to be extracted in a single integrated operation. The FSP also requires increased disclosures. Adoption of this rule did not have a material impact on our combined earnings in 2005. If this FSP had been applied to 2004, it would not have had a material effect on our earnings for that year.
      FAS No. 154: In 2005, the FASB issued FAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FAS No. 3,” which is effective January 1, 2006. Opinion 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This Statement requires retrospective application (restatement) to prior periods’ financial statements of changes in accounting principle. This Statement also applies to changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.
      FAS Interpretation No. 47: In March 2005, the FASB issued FAS Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FAS Statement No. 143,” “Accounting for Asset Retirement Obligations”, which is effective no later than December 31, 2005. This pronouncement clarifies that the term “conditional asset retirement obligation” as used in FAS Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. This interpretation is not expected to have a material impact on either our earnings or consolidated balance sheet.
      In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 is effective for fiscal years ending after November 15, 2006, and early application is encouraged. Legacy does not believe SAB 108 will have a material impact on our financial position or results of operations.
      In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“FAS 157”). This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted account principles and expands disclosure related to the use of fair value measures in financial statements. The Statement is to be effective for Legacy’s financial statements issued in 2008; however, earlier application is encouraged. The

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Statement will affect fair value measurements we make after adoption. Legacy is currently evaluating the timing of adoption.
Quantitative and Qualitative Disclosure About Market Risk
      The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
      Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to our natural gas production and the prevailing price for crude oil. Pricing for oil and natural gas has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, such as the strength of the global economy.
      We periodically enter into and anticipate entering into hedging arrangements with respect to a portion of our projected oil and natural gas production through various transactions that hedge the future prices received. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into put options, whereby we pay a premium in exchange for the right to receive a fixed price at a future date. At the settlement date we receive the excess, if any, of the fixed floor over the floating rate. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes.
      As of September 30, 2006, the fair market value of Legacy’s derivative positions was a net asset of $1.3 million. As of December 31, 2005, the fair market value of Legacy’s derivative positions, not including the liabilities of MBN Properties LP, was a liability of $1.9 million. Additionally, the fair market value of MBN Properties LP’s oil and natural gas hedge position as of December 31, 2005, was a liability of $1.45 million. Legacy Reserves LP has assumed these hedge positions. The oil and natural gas swaps for 2006 and through December 31, 2010 are tabulated in the table presented above under “— Cash Flow from Operations”
      If oil prices decline by $1.00 per Bbl, then the standardized measure of our combined proved reserves as of June 30, 2006 would decline from $315.5 million to $309.5 million, or (1.9%). If natural gas prices decline by $0.10 per Mcf, then the standardized measure of our combined proved reserves as of June 30, 2006 would decline from $315.5 million to $314.3 million, or (0.4%).
Interest Rate Risks
      At December 31, 2005, Legacy had debt outstanding of $52,473,000, which incurred interest at floating rates in accordance with its revolving credit facility and the subordinated notes payable. The average annual interest rate incurred by Legacy for year ended December 31, 2005 was 9.0%. A 1% increase in LIBOR on Legacy’s outstanding debt as of December 31, 2005 would result in an estimated $524,730 increase in annual interest expense. The subordinated debt interest rate is computed as Legacy’s interest rate to the senior lending group plus 4.0%. Following our private equity offering, all then existing debt was retired, and borrowings under our revolving credit facility bear interest at variable rates.
      On a pro forma basis, a 1% increase in LIBOR on Legacy’s debt of $106.8 million as of September 30, 2006 would result in an estimated $1,068,000 million increase in annual interest expense.

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BUSINESS
Overview
     Legacy Reserves LP
      We are an independent oil and natural gas limited partnership, headquartered in Midland, Texas, focused on the acquisition and exploitation of oil and natural gas properties primarily located in the Permian Basin of West Texas and southeast New Mexico. We were formed in October 2005 to own and operate the oil and natural gas properties that we acquired from our Founding Investors and three charitable foundations in connection with the closing of our private equity offering on March 15, 2006. Members of our management team have an average of 22 years of experience in the oil and natural gas industry and over 20 years of experience in the Permian Basin. Our primary business objective is to generate stable cash flows allowing us to make cash distributions to our unitholders and to increase quarterly cash distributions per unit over time through a combination of acquisitions of new and exploitation of our existing oil and natural gas properties.
      We have grown primarily through two activities: the acquisition of producing oil and natural gas properties and the exploitation of proved properties as opposed to higher risk exploration of unproved properties.
      In June and July 2006, in three separate transactions, we acquired 2.6 MMBoe of proved reserves and related operating rights for an aggregate purchase price of approximately $36.3 million in cash and 146,415 newly issued units. Please see “ —Acquisition Activities” below.
      Giving effect to our third quarter acquisition from Kinder Morgan, our oil and natural gas production and reserve data are as follows:
  •  we had proved reserves of approximately 20.2 MMBoe, of which 72% were oil and 78% were classified as proved developed producing, 4% were proved developed non-producing, and 18% were proved undeveloped as of June 30, 2006;
 
  •  our proved reserves had a standardized measure as of June 30, 2006 of $315.5 million; and
 
  •  our proved reserves to production ratio was approximately 16 years based on the average daily net production for the nine months ended September 30, 2006.
      Our average daily net production was 3,484 Boe/d for the nine months ended September 30, 2006, assuming we had owned all of our current properties as of January 1, 2006.
      During the period January 1, 2003 through December 31, 2005, we acquired approximately 7.0 MMBoe of proved reserves at a cost of approximately $76.8 million, or $10.95 per Boe of proved reserves. We further increased our proved reserves by approximately 7.0 MMBoe, comprised of revisions of previous estimates due to prices and performance of 3.3 MMBoe; revisions of previous estimates due to infill drilling, recompletions and stimulations of 3.2 MMBoe; and extensions and discoveries of 0.5 MMBoe at a cost of approximately $9.7 million, or $1.39 per Boe. Considering all reserve additions from acquisitions, revisions and extensions, during this period we added 14.0 MMBoe of proved reserves investing $86.5 million, for an overall proved reserve replacement cost of $6.17 per Boe.
      Our reserves are located primarily in the Permian Basin, one of the largest and most prolific oil and natural gas producing basins in the United States. The Permian Basin extends over 100,000 square miles in West Texas and southeast New Mexico and has produced over 24 billion Bbls of oil since its discovery in 1921. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. Our producing properties in the Permian Basin are mature fields with established decline curves predominately producing from tight oil reservoirs which are generally not subject to drainage, but are subject to pressure depletion under primary recovery. Approximately 77% of our production for the nine-month period ended September 30, 2006 was from properties under primary recovery, 19% from secondary recovery (waterflood), and 4% from tertiary recovery (CO2 injection). On a proved reserve basis, 76% are primary, 19% are secondary (waterflood), and 5% are tertiary (CO2) projects.

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Acquisition Activities
      We have and will continue to focus on identifying, evaluating, executing, integrating and exploiting acquisitions of oil and natural gas properties in the Permian Basin, a large basin characterized by fragmented ownership. During July 2005, there were more than 1,700 operators in the Permian Basin according to the Texas and New Mexico oil and natural gas regulatory commissions, and the top five operators accounted for less than 40% of the total oil production during that period. We believe that our track record and structure will allow us to favorably compete in the acquisition market.
      From January 1, 1999 through July 31, 2006, we invested approximately $146.0 million in 29 acquisitions, which amount excludes $7.0 million allocated to the purchase of operating rights related to the South Justis Field acquisition. Based on reserve data prepared at the time of these acquisitions, we added a total of approximately 22.7 MMBoe of proved reserves at a reserve acquisition cost of $6.42 per Boe. These additions include our September 2005 acquisition of approximately 5.6 MMBoe of proved reserves, as evaluated by LaRoche Petroleum Consultants, Ltd. as of September 30, 2005, from PITCO for $63.9 million in cash ($64.3 million, inclusive of asset retirement obligations), representing a proved reserve acquisition cost of $11.49 per Boe. The recent acquisitions discussed below are also included in the reserve acquisition cost calculation, but exclude the portion of the acquisition purchase price allocated to the operating rights related to the South Justis Field acquisition.
Recent Acquisitions
      On June 29, 2006, we acquired certain producing properties and related operating rights in the South Justis Field located in Lea County, New Mexico for a purchase price of $13.4 million cash and 146,415 newly issued units. We acquired a 15% operated working interest in the South Justis Unit, a waterflood installed in 1992 that contains 113 producing wells and 97 water injection wells producing approximately 952 gross (125 net) Boe/d for the six months ended June 30, 2006. As of June 30, 2006, total net proved reserves were approximately 0.69 MMBoe, 65% of which are classified as proved developed producing, 21% are proved developed non-producing and 14% are proved undeveloped. We have allocated $8.9 million of the $15.9 million net purchase price to the working interest and reserve acquisition resulting in a proved reserve acquisition cost of $12.88 per Boe, and the balance of $7.0 million was allocated to the related operating rights which entitle us to receive approximately $1.7 million of operating fees annually from third party owners of the properties. We expect to refracture stimulate 38 existing wells and infill drill twelve 20-acre locations over the next three years.
      Also on June 29, 2006 we closed an acquisition of additional operated leases in the Farmer Field, located in Crockett and Reagan counties of West Texas, from Larron Oil Corporation, for $5.6 million cash. We acquired a 100% operated interest in 50 wells producing 76 net Boe/d and net reserves as of June 30, 2006 of 0.44 MMBoe, all of which are classified as proved developed producing resulting in a proved reserve acquisition cost of $12.73 per Boe. Prior to the Larron acquisition, we operated 111 wells in the Farmer Field.
      On July 31, 2006, we closed the acquisition of properties from Kinder Morgan for approximately $17.3 million cash after closing adjustments. The Kinder Morgan properties contain 85 producing wells and 44 water injection wells located in nine fields in Texas and southeast New Mexico which produce approximately 300 Boe/d net as of July 31, 2006. We operate over 90% of the production. As of July 31, 2006, net proved reserves were 1.46 MMBoe, of which 88% are proved developed producing and 12% are proved undeveloped resulting in a proved reserve acquisition cost of $11.85 per Boe.
      We believe that our recent acquisitions will provide us with continuing opportunities to apply our operational knowledge to increase production and reserves from a variety of known producing formations since many of the acquired properties are near or in the same fields or formations as our other properties. For example, the Kinder Morgan acquisition included production in the Denton Field, which is our largest property in terms of reserve value and the Larron acquisition is adjacent to our existing wells in the Farmer Field, which is our largest property in terms of proved reserves. We believe these acquisitions will result in operational efficiencies.

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Exploitation Activities
      We have also grown reserves and production each year since 1999 through exploitation activities on our existing and acquired properties. Our exploitation activities include accessing additional productive formations in existing wellbores, formation stimulation, artificial lift equipment enhancement, infill drilling on closer well spacing, secondary (waterflood) and tertiary (CO2) recovery projects, drilling for deeper formations and completing unconventional and tight formations. From January 1, 2003 through December 31, 2005, our proved reserves increased by approximately 7.0 MMBoe, comprised of 3.3 MMBoe from revisions of previous estimates due to prices and performance; 3.2 MMBoe from revisions of previous estimates due to infill drilling, recompletions and stimulations; and 0.5 MMBoe through extensions and discoveries. Over the same period our reserve replacement rate, or the ratio of increases in proved reserves to production was 287% excluding acquisitions.
      The reserve replacement rate is calculated by taking the sum of reserve additions as a result of extensions and discoveries plus revisions of previous estimates, and dividing the sum by the total production over the same period. This reserve replacement calculation excludes acquisitions and sales of reserves to show reserve growth on existing properties. The data is derived from the volume disclosures contained in the financial statements contained in this prospectus. The proved reserve additions and produced volumes for the year ending December 31, 2005, are taken from our pro-forma volume tables. The reserve addition volumes for 2003 and 2004 as taken from the volume disclosures from the Moriah Group, Brothers Group, Paul T. Horne, and the charitable foundations. For the three year period of January 1, 2003 through December 31, 2005, increases in proved reserve were 7.0 MMBoe, which are divided by the net production over the same period of 2.4 MMBoe, resulting in a 287% reserve replacement rate.
      Reserve additions as a result of revisions of previous estimates and improved recovery are due to workovers and waterflood improvements, and due to increases in commodity prices. A significant decrease in commodity prices would result in a significant downward revision of our proved reserves. The revisions of previous estimates and improved recovery are generally limited to the proved developed producing reserve category. Reserve additions due to extensions and discoveries are primarily in the proved undeveloped reserve category. We use the reserve replacement rate as a measure to indicate whether we are replacing our production at a rate that will enable us to sustain our long term production profile. The reserve replacement rate does not indicate the producing profile or life of the reserves or economic value added. As of June 30, 2006, we have identified 117 gross (77 net) proved undeveloped drilling locations, 47 gross (10 net) recompletion and refracture stimulation projects and one tertiary (CO2) recovery expansion project on our properties, over 90% of which we intend to drill and execute over the next four years. Excluding acquisitions, we expect to make capital expenditures of approximately $10.3 million during the year ending December 31, 2007, including drilling 22 gross (12.9 net) development wells, executing 24 gross (4.1 net) recompletions and refracture stimulations and expanding one tertiary (CO2 ) recovery project. We currently have rigs operating or committed to drill 100% of our expected development wells for the year ending December 31, 2007.
Hedging Activities
      Our strategy includes hedging a majority of our oil and natural gas production over a three to five-year period. We have hedged approximately 69% of our expected oil and natural gas production from total proved reserves for the year ending December 31, 2007. We have also hedged approximately 61% of our expected oil and natural gas production from total proved reserves for 2008 through 2010. All of our hedges are in the form of fixed price swaps with average annual NYMEX prices of at least $61.51 per Bbl of oil and $7.99 per MMBtu of natural gas. In July 2006, we entered into basis swaps to receive floating NYMEX prices less a fixed basis differential and pay prices based on the floating Waha index, a natural gas hub in West Texas. The prices that we receive for our natural gas sales follow Waha more closely than NYMEX. The basis swaps thereby provide a better match between our natural gas sales and the settlement payments on our natural gas swaps. We have hedged approximately 100% of our NYMEX natural gas basis differential risk on our NYMEX natural gas swaps for 2007 through 2010.

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Business Strategy
      The key elements of our business strategy are to:
  •  Make accretive acquisitions of producing properties generally characterized by long-lived reserves with stable production and reserve exploitation potential. We seek to acquire long-lived reserves with moderate production decline rates and reserve exploitation potential. Our diverse property base across numerous fields provides opportunities for “bolt-on” acquisitions, whereby we increase our ownership in fields in which we already have a working interest. We also acquire interests in new fields. Since 1999, we have completed 29 acquisitions for a total purchase price of approximately $146 million, which amount excludes $7.0 million allocated to operating rights relating to the South Justis Field acquisition, at a reserve acquisition cost of $6.42 per Boe. We believe that our experience positions us to identify, evaluate, execute, integrate and exploit suitable acquisitions. Since we will distribute all of our available cash to our unitholders, we will depend on financing provided by commercial banks and other lenders and the issuance of debt and equity securities to finance any significant growth or acquisitions.
 
  •  Grow proved reserves and maximize cash flow and production through exploitation activities and operational efficiencies. We have a history of growing proved reserves and maximizing production through exploitation activities while focusing on operational efficiencies. As of June 30, 2006, we have identified 117 gross (77 net) proved undeveloped drilling locations, 47 gross (10 net) recompletion and refracture stimulation projects and one tertiary (CO2) recovery expansion project on our properties, over 90% of which we intend to drill and execute over the next four years. For the year ending December 31, 2007, we have budgeted approximately $10.3 million for exploitation projects on our properties.
 
  •  Focus on the Permian Basin. The long-lived, stable production profile of our Permian Basin assets is well suited to our business objective and should support our ability to generate stable cash flows. In addition, the fragmented ownership of properties in the Permian Basin make the Permian Basin well suited for our growth objectives. While we are currently focused on the Permian Basin, we will continue to assess opportunities in other areas providing long-lived reserves and may expand into those areas if attractive opportunities become available.
 
  •  Maintain financial flexibility. We intend to maintain substantial borrowing capacity under our revolving credit facility. We believe our internally generated cash flows and our borrowing capacity will provide us with the financial flexibility to execute our exploitation activities and pursue additional acquisitions of producing properties.
 
  •  Reduce commodity price risk through hedging. We enter into hedging arrangements to reduce the impact of oil and natural gas price volatility on our cash flow from operations. Our strategy includes hedging a significant portion of our future production over a three to five year period. For the year ending December 31, 2007, we have swapped floating prices for fixed prices on 671,637 Bbls of oil and 1,558,504 MMBtu of natural gas, which represents approximately 69% of our total expected net oil and natural gas production of 1,323 MBoe. By removing the price volatility from a significant portion of our oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flow from operations for those periods. Please read “Management’s Discussion and Analysis and Financial Condition and Results of Operations — Cash Flow from Operations.”
Competitive Strengths
      We believe that we are well positioned to successfully execute our business strategy because of the following competitive strengths:
  •  Proven acquisition and exploitation track record. We have historically grown our proved reserves and production through acquisitions and exploitation activities. During the period January 1, 2003 through December 31, 2005, we invested approximately $86.5 million and added approximately 14.0 MMBoe of proved reserves for a reserve replacement cost of $6.17 per Boe. The 14.0 MMBoe of proved reserve additions are comprised of approximately 7.0 MMBoe of property acquisitions, 3.3 MMBoe of

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  revisions to prior estimates due to prices and performance; 3.2 MMBoe of revisions of previous estimates due to infill drilling, recompletions, and stimulations; and 0.5 MMBoe of extensions and discoveries. Additionally, we have increased our production from 1,887 Boe/d for the year ended December 31, 2002, to 3,484 Boe/d for the nine months ended September 30, 2006, which includes the historical production attributed to all of the properties we owned as of September 30, 2006.
 
  •  Predictable, long-lived reserve base. Our properties are primarily located in mature fields characterized by a long history of stable production and low to moderate rates of production decline. According to the Texas and New Mexico oil and natural gas regulatory commissions, the properties in which we own interests have cumulatively produced over 1 billion Boe, gross.
 
  •  Diversified operations and operational control over approximately 70% of our current production. Our properties and operations are broadly distributed across the Permian Basin, producing from over 40 different formations. As of September 30, 2006, we produced oil and natural gas from a total of approximately 1,900 wells. We operate approximately 70% of our current production. Our largest field in terms of total proved reserves, which includes approximately 160 producing wells, represents less than 10% of our total standardized measure as of June 30, 2006. We believe that our diversified operations reduce our dependence on specific properties or producing wells, thereby reducing operational and reserve risk. In addition, we believe that our broad technical and operational expertise enables us to identify a wide range of production and reserve growth opportunities when evaluating acquisitions with reserve exploitation potential.
 
  •  Experienced management team with a vested interest in our success. The members of our management team have an average of over 20 years of experience in the oil and natural gas industry, with the majority of that time focused on the Permian Basin. During that time, which included several commodity price cycles, we made more than 20 acquisitions of producing oil and natural gas properties. We believe that our management’s experience in acquiring and developing oil and natural gas properties and its technical knowledge of the production characteristics of the formations and recovery methods in the Permian Basin will enable us to successfully identify, evaluate, execute, integrate and exploit acquisitions. Members of our management team, their families and their affiliated entities beneficially own a majority of our units. Please read “Security Ownership of Certain Beneficial Owners and Management.”

Description of Our Properties
      As of September 30, 2006 we owned interests in producing oil and natural gas properties in 146 fields in the Permian Basin, operated 733 gross productive wells and owned non-operated interests in 1,183 gross productive wells.

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      The following table sets forth information about our proved oil and natural gas reserves as of June 30, 2006 giving effect to our acquisition of the oil and natural gas properties from the Founding Investors and the charitable foundations and our South Justis, Farmer Field and Kinder Morgan acquisitions. The reserve data is based on our June 30, 2006 reserve reports. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.
                                           
    Consolidated
    Combined
    As of June 30, 2006
     
        Standardized Measure
    Proved Reserves    
            % of
Field   MMBoe   R/P   % Oil   Amount   Total
                     
                ($ in millions)    
Denton
     1.99       15.9       85.3 %   $ 31.9       10.1 %
Farmer
     2.13       22.1       66.0       27.1       8.6  
Langlie Mattix
     1.27       25.8       92.0       20.8       6.6  
Howard Glasscock/ Iatan/ Iatan East
     1.21       15.7       98.9       20.6       6.5  
Hobbs
     1.11       19.4       92.3       20.5       6.5  
Lea
     1.55       19.8       71.1       19.5       6.2  
                               
 
Total — Top 6 fields
     9.26       19.1       82.1 %   $ 140.4       44.5 %
All others
     10.90       13.7       63.4       175.1       55.5  
                               
 
Total
     20.16       15.8       72.0 %   $ 315.5       100.0 %
                               
Summary of Oil and Natural Gas Properties and Projects
      Our most significant fields are the Denton, Farmer, Langlie Mattix, Howard Glasscock/ Iatan/ Iatan East Howard, Hobbs and Lea fields. As of June 30, 2006, these six fields accounted for approximately 44.5% of our total estimated proved reserves.
      Denton Field. The Denton field is an oil and natural gas field located in Lea County, New Mexico. This field was discovered in 1950 and through June 30, 2006, our properties in this field have gross cumulative production of 46.3 MMBbls of oil and 27.7 Bcf of natural gas. The Devonian Formation at depths of 11,000 to 12,700 feet is the primary reservoir in the Denton field. Additional production has been developed in the Wolfcamp Formation at depths of 8,900 to 9,600 feet. We operate 16 wells in the Denton field with working interests ranging from 86% to 100% and net revenue interests ranging from 77.2% to 87.5%. We also own another 12 wells with a 15.0% average non-operated working interest. As of June 30, 2006, our properties in the Denton field contained 2.0 MMBoe (85% oil) of net proved reserves with a standardized measure of $31.9 million. The estimated average net daily production from this field is 345 Boe/d for the second half of 2006 as projected in our reserve report. The estimated reserve life (R/P) for the field is 15.9 years.
      The Denton field has a natural water drive and most of the wells produce large amounts of water utilizing high volume lift submersible pumps. We have one proved developed non-producing, or PDNP, project identified in the Devonian formation of this field and three unclassified high volume lift candidates in the Wolfcamp formation of this field.
      Farmer Field. The Farmer field is an oil and natural gas field located in Crockett and Reagan County, Texas. This field was discovered in 1953 and through June 30, 2006, our properties in this field have gross cumulative production of 5.6 MMBbls of oil and 12.3 Bcf of natural gas. The San Andres Formation at depths of 2,100 to 2,600 feet is the primary reservoir in the Farmer field. We operate 161 wells (153 producing, 8 injecting) in the Farmer field with a 100.0% average working interest and a 87.3% average net revenue interest. As of June 30, 2006, our properties in the Farmer field contained 2.13 MMBoe (66% oil) of net proved reserves with a standardized measure of $27.1 million. The estimated average net daily production from this field is 265 Boe/d for the second half of 2006 as projected in our reserve report. The estimated reserve life (R/ P) for the field is 22.1 years.

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      The Farmer field has been developed using 20-acre spacing with the exception of a pilot 10-acre spacing area that includes 11 10-acre wells. We currently have 33 10-acre proved undeveloped, or PUD, locations in this field and an additional 84 unproved 10-acre locations.
      Langlie Mattix Field. The Langlie Mattix field is an oil and natural gas field located in Lea County, New Mexico. This field was discovered in the late 1930s and through June 30, 2006, our properties in this field have gross cumulative production of 18.2 MMBbls of oil and 16.4 Bcf of natural gas. The Queen Formation at depths of 3,400 to 3,800 feet is the primary reservoir in the Langlie Mattix field. We operate 99 wells (77 producing, 22 injecting) in the Langlie Mattix Penrose Sand Unit, a subdivision of the Langlie Mattix Field, with a 50.7% average working interest and a 44.1% average net revenue interest. We also operate two other properties with 100% and 82.4% working interests and 82.0% and 67.4% net revenue interests. As of June 30, 2006, our properties in the Langlie Mattix field contained 1.27 MMBoe (92% oil) of net proved reserves with a standardized measure of $20.8 million. The estimated average net daily production is 135 Boe/d for the second half of 2006 as projected in our reserve report. The estimated reserve life (R/P) for the field is 25.8 years.
      The Langlie Mattix Penrose Sand Unit was drilled in the late 1930s and early 1940s on 40-acre spacing. Waterflooding commenced in 1958. There have been 14 20-acre infill wells drilled on the Unit; five drilled in 1983, three drilled in 1992, and six drilled in 2004. All three 20-acre infill programs were successful. We have 30 20-acre infill proved undeveloped locations and an additional 55 unproved 20-acre locations.
      Howard Glasscock, Iatan and Iatan East Howard Fields. The Howard Glasscock, Iatan and Iatan East Howard fields adjoin one another and are located in Howard and Mitchell counties, Texas. These fields were discovered in 1925 and through June 30, 2006, our properties in these fields have a gross cumulative production of 10.4 MMBbls of oil and 0.6 Bcf of natural gas. These fields produce from multiple formations of Permian age which primarily include the San Andres, Yates, Seven Rivers, Queen, Clearfork and Glorieta Formations from 1,000 to 3,700 feet as well as the Wolfcamp and Canyon Formations from 5,100 to 7,400 feet. We operate 137 wells (127 producing, 10 injecting) in these fields with working interests ranging from 62.5% to 100.0% and net revenue interests ranging from 46.8% to 87.5%. As of June 30, 2006, our properties in the Howard Glasscock, Iatan and Iatan East Howard fields contained 1.2 MMBoe (99% oil) of net proved reserves with a standardized measure of $20.6 million. The estimated average net daily production from these fields is 212 Boe/d for the second half of 2006 as projected in our reserve report. The estimated reserve life (R/P) for these fields is 15.7 years.
      Hobbs Field. The Hobbs field is an oil and natural gas field located in Lea County, New Mexico. The field was discovered in 1928 and through June 30, 2006 our properties in the Hobbs field have a combined gross cumulative production of 350.4 MMBbls of oil and 395.8 Bcf of natural gas. The Grayburg and San Andres formations at depths of 3,850 to 4,300 feet are the primary reservoirs in the Hobbs field. We have a non-operated working interest in two Occidental Permian Ltd. operated properties, the North Hobbs Unit and the South Hobbs Unit. Working interests are 1.3% and 1.1% respectively with net revenue interests of 1.1% and 0.9% respectively. We also operate one well producing from the Drinkard formation with a 100% working interest and 87.5% net revenue interest. There are a total of 430 active wells (262 producing, 168 injecting) on these properties and they contain 1.1 MMBoe (92% oil) of net proved reserves with a standardized measure of $20.5 million. The estimated average net daily production from the Hobbs field is 158 Boe/d for the second half of 2006 as projected in our reserve report. The estimated reserve life (R/P) for these fields is 19.4 years.
      The North Hobbs Unit is currently being CO2 flooded with ongoing expansion of the enhanced oil recovery project. The South Hobbs Unit is currently being waterflooded and has potential for enhanced oil recovery using CO2 injection, but has not been evaluated by our engineers or LaRoche Petroleum Consultants, Ltd.
      Lea Field. The Lea field is an oil and natural gas field located in Lea County, New Mexico. This field was discovered in 1960 and through June 30, 2006 our properties in this field have gross cumulative production of 10.3 MMBbls of oil and 30.5 Bcf of natural gas. The Devonian Formation at depths of 14,200 to 14,600 feet is the primary reservoir in the Lea field. Additional production has been developed in the

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Morrow Formation at depths of 12,800 to 13,200 feet and the Bone Spring Formation at depths of 9,300 to 10,500 feet. We operate 14 wells in the Lea Field with a 68.7% average working interest and a 60.1% average net revenue interest. We also own another two wells with a 10.3% average non-operated working interest. As of June 30, 2006, our properties in the Lea field contained 1.6 MMBoe (71% oil) of net proved reserves with a standardized measure of $19.5 million. The estimated average net daily production from this field is 215 Boe/d for the second half of 2006 as projected in our reserve report. The estimated reserve life (R/P) for the Lea field is 19.8 years.
      We have nine proved undeveloped locations in the Bone Spring Formation which are all 40-acre infill wells. There is also significant production from the Delaware formation less than a mile northwest of the Lea field and we are currently evaluating development of the Delaware formation in the Lea field. The Delaware formation is not included in our reserve report.
Oil and Natural Gas Data
     Proved Reserves
      The following table sets forth a summary of information related to our estimated net proved reserves as of the dates indicated based on our reserve reports prepared by LaRoche Petroleum Consultants, Ltd. including:
  •  our combined reserves as of December 31, 2005, giving effect to our acquisition of the oil and natural gas properties from the Founding Investors and charitable foundations on March 15, 2006; we refer to this presentation of reserves as our “combined for initial formation transactions” reserves in this prospectus; and
 
  •  our combined reserves as of December 31, 2005 and June 30, 2006, giving effect to our acquisition of the oil and natural gas properties from the Founding Investors and charitable foundations on March 15, 2006 as well as our South Justis, Farmer Field and Kinder Morgan acquisitions completed in June and July 2006; we refer to this presentation of reserves as our “consolidated combined” reserves in this prospectus.
      Summaries of the June 30, 2006 reserve reports prepared by LaRoche Petroleum Consultants, Ltd. are attached as Appendix C. The estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency. Standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.
                                             
    Combined for        
    Initial Formation Transaction    
        Consolidated
        Combined
    As of    
    December 31,   As of   As of
        December 31,   June 30,
    2003   2004   2005   2005   2006
                     
Reserve Data:
                                        
Estimated net proved reserves:
                                        
 
Oil (MMBbls)
     8.5       10.3       12.3       14.1       14.5  
 
Natural gas (Bcf)
     28.3       27.8       33.8       35.4       33.9  
                               
   
Total (MMBoe)
     13.2       15.0       17.9       20.0       20.2  

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    Combined for        
    Initial Formation Transaction    
        Consolidated
        Combined
    As of    
    December 31,   As of   As of
        December 31,   June 30,
    2003   2004   2005   2005   2006
                     
Proved developed reserves (MMBoe)
     13.2       14.7       14.9       16.8       16.5  
Proved undeveloped reserves (MMBoe)
     —       0.3       3.0       3.2       3.7  
Proved developed reserves as a percentage of total proved reserves
     100 %     98 %     83 %     84 %     82 %
Standardized measure (in millions)(a)
   $ 115.4     $ 159.9     $ 277.2     $ 307.8     $ 315.5 (b)
Oil and Natural Gas Prices(c):
                                        
Oil — NYMEX WTI per Bbl
   $ 32.52     $ 43.45     $ 61.05     $ 61.05     $ 73.92  
Natural gas — NYMEX Henry Hub per MMBtu
   $ 6.19     $ 6.15     $ 11.25     $ 11.25     $ 6.06  
 
(a) 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 (using prices and costs in effect as of the period end date) without giving effect to non-property related expenses such as general administrative expenses, debt service and future income tax expenses or to depletion, depreciation and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities.”
 
(b) The standardized measure as of September 30, 2006 was $243.8 million based on an internal reserve report using NYMEX oil and natural gas prices of $62.91 per barrel and $5.62 per MMBtu, respectively, as of market close on September 29, 2006, the last trading day of the third quarter, with these representative prices adjusted by field to arrive at the appropriate net price.
 
(c) Oil and natural gas prices as of each date are based on NYMEX prices per Bbl of oil and per MMBtu of natural gas at such date, with these representative prices adjusted by field to arrive at the appropriate net price.
      Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.
      The data in the above table 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. Please read “Risk Factors — Our estimated reserves are based on many assumptions that may prove inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”
      Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. 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 Financial Accounting Standard Board pronouncements, 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.

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      From time to time, we engage LaRoche Petroleum Consultants, Ltd. to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither LaRoche Petroleum Consultants, Ltd. nor any of its employees has any interest in those properties and the compensation for these engagements is not contingent on their estimates of reserves and future net revenues for the subject properties. During 2005, we paid LaRoche Petroleum Consultants, Ltd. approximately $200,000 for such reserve and economic evaluations.
Production and Price History
      The following table sets forth a summary of unaudited information with respect to our production and sales of oil and natural gas for the periods indicated, including:
  •  the historical production and sales of oil and natural gas data of the Moriah Group as of December 31, 2003, 2004 and 2005;
 
  •  our combined production and sales of oil and natural gas data for the year ended December 31, 2005, giving effect to our acquisition of the oil and natural gas properties from the Founding Investors and charitable foundations on March 15, 2006 as if it had occurred on January 1, 2005; we refer to this presentation of production and sales of oil and natural gas data as our “combined for initial formation transactions” production in this prospectus; and
 
  •  our combined production and sales of oil and natural gas data for the year ended December 31, 2005 and the nine months ended September 30, 2006, giving effect to our acquisition of the oil and natural gas properties from the Founding Investors and charitable foundations on March 15, 2006 as well as our South Justis, Farmer Field and Kinder Morgan acquisitions completed in June and July 2006 as if they had occurred on January 1, 2005; we refer to this presentation of production and sales of oil and natural gas data as our “consolidated combined” production in this prospectus.
                                                   
        Combined   Consolidated
    Historical   for Initial   Combined
        Formation    
        Transactions       Nine Months
    Year Ended December 31,   Year Ended   Year Ended   Ended
        December 31,   December 31,   September 30,
    2003   2004   2005   2005   2005   2006
                         
Net Production:
                                                
 
Oil (MBbls)
     279       286       354       748       922       648  
 
Natural gas (MMcf)
     848       783       1,027       2,282       2,472       1,815  
 
Total (MBoe)
     420       416       525       1,128       1,334       951  
 
Average daily (Boe/d)
     1,152       1,138       1,438       3,090       3,655       3,484  
Average Sales Prices (including hedges)(a):
                                                
 
Oil (per Bbl)
   $ 28.40     $ 36.24     $ 38.94 (b)   $ 38.42 (c)   $ 41.34 (c)   $ 50.28 (d)
 
Natural gas (per Mcf)
   $ 4.02     $ 5.04     $ 5.45     $ 6.06     $ 6.05     $ 13.76  
 
Combined (per Boe)
   $ 26.98     $ 34.40     $ 36.92 (b)   $ 37.73 (c)   $ 39.79 (c)   $ 60.56 (d)
Average Sales Prices (including realized hedge gains/losses)(e):
                                                
 
Oil (per Bbl)
   $ 26.79     $ 38.61     $ 41.51 (b)   $ 41.68 (c)   $ 43.96 (c)   $ 52.57 (d)
 
Natural gas (per Mcf)
   $ 4.15     $ 4.89     $ 7.13     $ 6.76     $ 6.70     $ 9.67  
 
Combined (per Boe)
   $ 26.17     $ 35.74     $ 41.93 (b)   $ 41.31 (c)   $ 42.80 (c)   $ 54.30 (d)

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        Combined   Consolidated
    Historical   for Initial   Combined
        Formation    
        Transactions       Nine Months
    Year Ended December 31,   Year Ended   Year Ended   Ended
        December 31,   December 31,   September 30,
    2003   2004   2005   2005   2005   2006
                         
Average Sales Prices (excluding hedges):
                                                
 
Oil (per Bbl)
   $ 28.38     $ 38.45     $ 51.48     $ 51.08     $ 51.59     $ 63.41  
 
Natural gas (per Mcf)
   $ 4.36     $ 5.04     $ 7.13     $ 6.76     $ 6.70     $ 6.74  
 
Combined (per Boe)
   $ 27.66     $ 35.92     $ 48.65     $ 47.53     $ 48.07     $ 56.11  
Average Unit Costs Per Boe:
                                                
 
Oil and natural gas production expenses
   $ 8.32     $ 10.44     $ 12.14     $ 10.67     $ 11.21     $ 13.32  
 
Production taxes
   $ 1.57     $ 2.23     $ 3.12     $ 3.06     $ 3.18     $ 3.65  
 
General and administrative expenses
   $ 1.29     $ 1.76     $ 2.58     $ 3.43     $ 2.29     $ 3.96  
 
Depletion, depreciation, amortization and accretion
   $ 1.82     $ 2.12     $ 4.36     $ 13.38     $ 13.84     $ 16.95  
 
(a)  Includes both the realized and unrealized hedge gains and losses from Legacy’s oil and natural gas swaps. Since Legacy does not specifically designate its commodity derivative instruments as cash flow hedges, current earnings reflect a mark-to-market adjustment for these instruments. Unrealized gains and losses represent a current period mark-to-market adjustment for commodity derivatives which will be settled in future periods. See Note 10 on page F-35 for details regarding Legacy’s unrealized gains and losses.
(b)  Includes the effects of approximately $2.0 million of derivative premiums for the year ended December 31, 2005 to cancel and reset 2006 oil swaps from $51.31 to $59.38 per Bbl and approximately $0.8 million of premiums paid on July 22, 2005 for an option to enter into a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised.
(c)  Includes the effects of approximately $3.5 million of derivative premiums for the year ended December 31, 2005 to cancel and reset 2006 oil swaps from $51.31 to $59.38 per Bbl and approximately $0.8 million of premiums paid on July 22, 2005 for an option to enter into a $55.00 per Bbl oil swap related to the PITCO acquisition that was not exercised.
(d)  Includes the effect of approximately $4.0 million of derivative premiums for the nine month period ending September 30, 2006 to cancel and reset 2007 oil swaps from $60.00 to $65.82 per barrel for 372,000 barrels and for 2008 oil swaps from $60.50 to $66.44 per barrel for 348,000 barrels, which reflected the prevailing oil swap market at the time of the reset.
(e)  Includes only the realized hedge gains (losses) from Legacy’s oil and natural gas swaps.
Productive Wells
      The following table sets forth information at July 31, 2006 relating to the productive wells in which we owned a working interest as of that date. 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.
                                   
    Oil   Natural Gas
         
    Gross   Net   Gross   Net
                 
Operated
     683       512.11       50       42.23  
Non-operated
     1,106       57.40       77       12.61  
 
Total
     1,789       569.51       127       54.84  

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Developed and Undeveloped Acreage
      The following table sets forth information as of July 31, 2006 relating to our leasehold acreage.
                                 
    Developed Acreage(a)   Undeveloped Acreage(b)
         
    Gross(c)   Net(d)   Gross(c)   Net(d)
                 
Total
     169,899       51,618       —       —  
 
(a) Developed acres are acres spaced or assigned to productive wells or wells capable of production.
 
(b) Undeveloped acres are acres which are not held by commercially producing wells, regardless of whether such acreage contains proved reserves. All of our proved undeveloped locations are located on acreage currently held by production.
 
(c) 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.
 
(d) 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.
Drilling Activity
      The following table sets forth information, on a combined basis, with respect to wells completed by the Moriah Group, Brothers Group, H2K, and the charitable foundations, during the years ended December 31, 2002, 2003 and 2004. No information relating to the PITCO properties is included in these historical annual periods. The drilling activities associated with the aforementioned entities and the PITCO properties (for the period from September 14, 2005 through December 31, 2005) are shown for the year ended December 31, 2005. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of oil and natural gas, regardless of whether they produce a reasonable rate of return.
                               
    Combined
     
    Year Ended
    December 31,
     
    2003   2004   2005
             
Gross:
                        
 
Development
                        
   
Productive
     5       12       12  
   
Dry
     1       —       —  
                   
     
Total
     6       12       12  
 
Exploratory
                        
   
Productive
     —       2       —  
   
Dry
     1       1       1  
                   
     
Total
     1       3       1  

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    Combined
     
    Year Ended
    December 31,
     
    2003   2004   2005
             
Net:
                        
 
Development
                        
   
Productive
     1.0       3.0       1.6  
   
Dry
     0.3       —       —  
                   
     
Total
     1.3       3.0       1.6  
 
Exploratory
                        
   
Productive
     —       0.2       —  
   
Dry
     1.0       0.2       0.1  
                   
     
Total
     1.0       0.4       0.1  
Summary of Exploitation Projects
      We are currently pursuing an active exploitation strategy. We estimate that our capital expenditures for the year ending December 31, 2007 will be approximately $10.3 million for development drilling, recompletions and refracture stimulation and other exploitation related projects to implement this strategy. We intend to drill 22 gross (12.9 net) development wells and execute 24 gross (4.1 net) recompletions and refracture simulations and expanding one tertiary (CO2) recovery project. All of these exploitation projects are located in the Permian Basin.
Operations
General
      We operate approximately 70% of our net daily production of oil and natural gas. We design and manage the development, recompletion or workover for all of the wells we operate and supervise operation and maintenance activities. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. Our Founding Investors have historically employed, and we expect to employ in the future, drilling, production, and reservoir engineers, geologists and other specialists who have worked and will work to improve production rates, increase reserves, and lower the cost of operating our oil and natural gas properties. Our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies. We charge the non-operating partners an operating fee for operating the wells.
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. In the Permian Basin this amount ranges from 12.5% to 25.0% resulting in a 87.5% to 75.0% net revenue interest to us. Most of our leases are held by production and do not require lease rental payments.
South Justis Unit Operating Agreement
      In connection with our acquisition of the South Justis Unit from Henry Holding LP on June 29, 2006, we became the successor in interest to Henry Holding LP as unit operator under the Unit Operating Agreement. As unit operator, we are entitled to receive from the other working interest owners a per well operating fee which we expect to be an aggregate of $1.7 million annually and is subject to an annual cost escalator. Under the terms of the Unit Agreement, we may be removed as unit operator upon default or failure to perform our duties by a vote of two or more working interest owners representing at least 80% of

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the working interest other than the interest held by us. In the event that we transfer our working interest ownership, we will be removed as unit operator.
Marketing and Major Purchasers
      For the year ended December 31, 2005, sales of oil to ConocoPhillips, Navajo Crude Oil Marketing, a subsidiary of Holly Corporation, and Plains Marketing, LP, a subsidiary of Plains All American, L.P., accounted for approximately 11%, 16% and 16%, respectively, of our total oil and natural gas sales on a combined basis excluding the PITCO properties prior to September 15, 2005. Our oil sales prices are based on formula pricing and calculated using the appropriate buyer’s posted price, plus Platt’s P-Plus monthly average, plus the Midland-Cushing differential less a transportation fee.
      For the year ended December 31, 2005, no single natural gas purchaser accounted for more than 10% of our oil and natural gas sales on a combined basis excluding the PITCO properties prior to September 15, 2005.
      If we were to lose any one of our oil or natural gas purchasers, the loss could temporarily delay production and sale of our oil and natural gas in that particular purchaser’s service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser. However, if one or more of our larger purchasers ceased purchasing oil or natural gas altogether, the loss of such purchasers could have a detrimental effect on our production volumes in general and on our ability to find substitute purchasers for our production volumes.
Hedging Activity
      We enter into hedging transactions with unaffiliated third parties with respect to oil and natural gas prices to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. All of our hedges in place are NYMEX financial swaps, which do not require option premiums. Our hedges either swap floating prices for fixed prices indexed on NYMEX for both oil and natural gas or swap the NYMEX index price to an index that reflects a geographical area of production, in our case, the Waha natural gas index. We do not have any interest rate swaps in place. For a more detailed discussion of our hedging activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operations” and “— Quantitative and Qualitative Disclosures About Market Risk.”
Competition
      We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry.
      We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our exploitation program.

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Title to Properties
      Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title opinions have been obtained on a significant portion of our properties.
      As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.
      We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.
Seasonal Nature of Business
      Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months thereby effecting the price we receive for natural gas. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation.
Environmental Matters and Regulation
      General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:
  •  require the acquisition of various permits before drilling commences;
 
  •  restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;
 
  •  limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
 
  •  require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
      These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.
      The following is a summary of some of the existing laws, rules and regulations to which our operations are subject.

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      Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
      Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
      We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploitation and production for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.
      Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
      Air Emissions. The Federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations.
      National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for

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public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.
      OSHA and Other Laws and Regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in compliance with these applicable requirements and with other OSHA and comparable requirements.
      Recent studies have suggested that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention of Climate Change, also known as the “Kyoto Protocol”. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil and natural gas, and refined petroleum products, are “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. For example, California recently adopted the “California Global Warming Solutions Act of 2006”, which required the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states of the United States could adversely affect our operations and demand for our products. Additionally, in late 2006, the U.S. Supreme Court will review the U.S. Circuit Court of Appeals for the District of Columbia’s ruling in Massachusetts, et al. v. EPA, in which the appellate court held that the U.S. Environmental Protection Agency had discretion under the Clean Air Act to refuse to regulate carbon dioxide emissions from mobile sources. A Supreme Court reversal of the appellate decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in U.S. federal courts in a manner unfavorable to our industry. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
      We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2005. Additionally, as of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2006. However, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operation.
Other Regulation of the Oil and Natural Gas Industry
      The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.
      Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including

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oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
      Drilling and Production. Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:
  •  the location of wells;
 
  •  the method of drilling and casing wells;
 
  •  the surface use and restoration of properties upon which wells are drilled;
 
  •  the plugging and abandoning of wells; and
 
  •  notice to surface owners and other third parties.
      State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
      Natural gas regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.
      Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.
      State regulation. The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.
      The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

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Employees
      We have 23 full-time employees, including eight petroleum engineers, five accountants and two landmen, none of whom are subject to collective bargaining agreements. We will also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed. Please read “Management — Reimbursement of Expenses of Our General Partner.” The Founding Investors have favorable relationships with their employees, and we believe that we will have a favorable relationship with our employees.
Offices
      We currently lease approximately 35,000 square feet of office space in Midland, Texas at 303 W. Wall Street, Suite 1600, where our principal offices are located, from TCTB Partners, a limited partnership of which Dale A. Brown, Cary D. Brown and Kyle A. McGraw are limited partners. Please read “Certain Relationships and Related Transactions — Transactions with Executive Officers, Directors and Principal Unitholders.” The lease for our Midland office expires in August 2011.
Legal Proceedings
      Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

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MANAGEMENT
Management of Legacy Reserves LP
      The directors and officers of Legacy Reserves GP, LLC, as our general partner, manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Other than through their ability to elect directors of our general partner as described below, unitholders will not be entitled to directly or indirectly participate in our management or operation.
      Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.
      The limited liability agreement of our general partner provides for a seven member board of directors. Prior to an initial public offering resulting in proceeds of not less than $20 million that results in our units being traded on a national securities exchange or the Nasdaq Stock Market, all of the directors of our general partner will be elected by its owners (currently our Founding Investors) and not by our unitholders, except in the following circumstances:
  •  if the owners of our general partner own less than 50% but at least 35% of our units, the unitholders, including the general partner and its affiliates, will be entitled to elect three of the seven directors;
 
  •  if the owners of our general partner own less than 35% but at least 20% of our units the unitholders, including the general partner and its affiliates, will be entitled to elect five of the seven directors; and
 
  •  if the owners of our general partner own less than 20% of our units the unitholders, including the general partner and its affiliates, will be entitled to elect all of the directors.
      Following an initial public offering resulting in proceeds of not less than $20 million that results in our units being traded on a national securities exchange or the Nasdaq Stock Market, our unitholders, including the general partner and its affiliates, will be entitled to elect all of the directors of our general partner. Please read “The Partnership Agreement — Meetings; Voting.”
      Three members of the board of directors of our general partner serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by any national securities exchange on which our securities may be listed and the Exchange Act and other federal securities laws. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, the board of directors of our general partner has an audit committee of three directors who meet the independence and experience standards established by the NASDAQ Global Market and the Exchange Act. The audit committee will review our external financial reporting, recommend engagement of our independent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. The board of directors of our general partner also has a compensation committee, consisting of three independent members, with the limited function of administering our long-term incentive plan and any future compensation plans. Additionally, the board of directors of our general partner has a nominating committee, consisting of three independent members, that will nominate candidates to serve on the board of directors of our general partner.
      Independent members of the board of directors of our general partner serve as the members of the conflicts, audit and compensation committees. We are not required to have a majority of independent directors on the board of directors of our general partner; however, we currently have a majority of independent directors on the board of directors of our general partner.

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Directors and Executive Officers of Our General Partner
      The following table shows information for the directors and executive officers of our general partner. Directors are elected for one-year terms.
             
Name   Age   Position with Legacy Reserves GP, LLC
         
Cary D. Brown
     39     Chief Executive Officer and Chairman of the Board
Steven H. Pruett
     45     President, Chief Financial Officer and Secretary
Kyle A. McGraw
     45     Executive Vice President — Business Development and Land and Director
Paul T. Horne
     44     Vice President — Operations
William M. Morris
     54     Vice President, Chief Accounting Officer and Controller
Dale A. Brown
     63     Director
G. Larry Lawrence
     55     Director and Member of Audit, Conflicts and Nominating Committees
William D. Sullivan
     50     Director and Member of Audit, Compensation, Conflicts and Nominating Committees
S. Wil VanLoh, Jr. 
     35     Director and Member of Audit and Compensation Committees
Kyle D. Vann
     58     Director and Member of Compensation, Conflicts and Nominating Committees
      Directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers of our general partner serve at the discretion of the board of directors. None of our executive officers and directors are related except for Dale A. Brown and Cary D. Brown, who are father and son.
      Cary D. Brown is Chairman of the board of directors of our general partner and Chief Executive Officer of our general partner and has served in such capacities since our founding in October 2005. Prior to October 2005, Mr. Brown co-founded two businesses, Moriah Resources, Inc. and Petroleum Strategies, Inc. Moriah Resources, Inc. was formed in 1992 to acquire oil and natural gas reserves. Petroleum Strategies, Inc. was formed in 1991 to serve as a qualified intermediary in connection with the execution of Section 1031 transactions for major oil companies, super-independents and private companies. Mr. Brown has served as Executive Vice President of Petroleum Strategies, Inc. since its inception in 1991. Mr. Brown served as an auditor for Grant Thornton in Midland, Texas from January 1990 to June 1991 and for Deloitte & Touche in Houston, Texas from June 1989 to December 1989. Mr. Brown is a certified public accountant. In 1995, Mr. Brown also founded and organized The Executive Oil Conference held in Midland, Texas, which draws over 300 oil and natural gas industry professionals each year. Mr. Brown has a Bachelors of Business Administration, with honors, from Abilene Christian University. Mr. Brown has 17 years of experience in the oil and natural gas industry with 15 years of experience in the Permian Basin.
      Steven H. Pruett is President, Chief Financial Officer and Secretary of our general partner and has served as President and Chief Financial Officer since our founding in October 2005. From January 2005 until he joined our general partner, Mr. Pruett served as a Managing Director at Quantum Energy Partners, a private equity group focused in the energy industry. From August 2004 to December 2004, Mr. Pruett was the President of PSI Management LLC, where his focus was investing in oil and natural gas projects in the Permian Basin. From June 2002 to July 2004, Mr. Pruett was the President of Petroleum Place and its subsidiary, P2 Energy Solutions, an acquisition and divestment advisor and accounting and land software systems developer serving over 100 public oil and natural gas companies. From June 2001 to June 2002, Mr. Pruett was employed by First Permian as its President and Chief Executive Officer until its sale to Energen Corporation. From April 2000 to May 2001, Mr. Pruett served as a Vice President of Enron North America Corp., where he managed 12 active oil and natural gas joint ventures and served as chairman of CGAS, an Appalachian oil and natural gas company. From April 1995 to March 2000, Mr. Pruett was President and Chief Executive Officer of First Reserve Oil & Gas Co., a Permian Basin and Oklahoma oil

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and natural gas property acquisition and exploitation company. Mr. Pruett has a Bachelor of Science in Petroleum Engineering, with high honors, from the University of Texas and a Masters of Business Administration from Harvard Business School where he was a Baker Scholar. Mr. Pruett has 23 years of experience in the oil and natural gas industry with 18 years of experience in the Permian Basin.
      Kyle A. McGraw is a member of the board of directors of our general partner and also serves as the Executive Vice President — Business Development and Land of our general partner and has served in such capacities since our founding in October 2005. Mr. McGraw joined Brothers Production Company in 1983, and has served as its General Manager since 1991 and became President in 2003. During his 23 year tenure at Brothers Production Company, Mr. McGraw has served in numerous capacities including reservoir and production engineering, acquisition evaluation and land management. Mr. McGraw is a registered professional engineer (inactive status) in the state of Texas. Mr. McGraw has a Bachelor of Science in Petroleum Engineering from Texas Tech University. Mr. McGraw has 24 years of experience in the oil and natural gas industry in the Permian Basin.
      Paul T. Horne is Vice President — Operations of our general partner and has served in such capacity since our founding in October 2005. From January 2000 to the present, Mr. Horne has served as Operations Manager of Moriah Resources, Inc. From January 1985 to January 2000, Mr. Horne worked for Mobil E&P U.S. Inc. in a variety of petroleum engineering and operations management roles primarily in the Permian Basin. Mr. Horne has a Bachelor of Science in Petroleum Engineering, with honors, from Texas A&M University. Mr. Horne has 23 years of experience in the oil and natural gas industry with 21 years of experience in the Permian Basin.
      William M. Morris is Vice President, Chief Accounting Officer and Controller of our general partner and has served in such capacity since our founding in October 2005. From January 2000 until he joined our general partner in October 2005, Mr. Morris served as Financial Reporting Manager of Titan Exploration Inc. (from January 2000 through May 2000) and continued in that position upon Titan Exploration Inc.’s merger with the Permian Basin Business Unit of Unocal to form Pure Resources, Inc. (from May 2000 to January 2003) and most recently as a Financial Manager for Pure Resources, Inc. (from February 2003 to September 2005). Mr. Morris is a certified public accountant. Mr. Morris has a Bachelor of Science in Applied Mathematics, with honors, from the School of Engineering and Applied Science of the University of Virginia and a Master of Business Administration from Colgate Darden Graduate School of Business Administration of the University of Virginia. Mr. Morris has 26 years of experience in the oil and natural gas industry with 25 years of experience in the Permian Basin.
      Dale A. Brown is a member of the board of directors of our general partner and has served in such capacity since our founding in October 2005. Mr. Brown has been President of Moriah Resources, Inc. since its inception in 1992 and President of Petroleum Strategies, Inc. since he co-founded it in 1991 with his son, Cary D. Brown. Mr. Brown is a certified public accountant. Mr. Brown has a Bachelor of Science in Accounting from Pepperdine University.
      G. Larry Lawrence has been a member of the board of directors of our general partner since May 1, 2006. Since June 2006, Mr. Lawrence has been self employed as a management consultant doing business as Cresent Consulting. From May 2004 through April 2006 Mr. Lawrence served as Controller of Pure Resources an exploration and production company and a wholly owned subsidiary of Unocal Corporation which was acquired by Chevron Corporation. From June 2000 through May 2004, Mr. Lawrence was a practice manager of the Parson Group, LLC, a financial management consulting firm whose services included Sarbanes Oxley engagements with oil and natural gas industry clients. From 1973 through May 2000, Mr. Lawrence was employed by Atlantic Richfield Company (ARCO) where he most recently (from 1993 through 2000) served as Controller of ARCO Permian. Mr. Lawrence has a Bachelor of Arts in Accounting, with honors, from Dillard University.
      William D. (Bill) Sullivan was appointed to the board of directors of our general partner upon completion of our private equity offering on March 15, 2006. Since May 2004, Mr. Sullivan has served as a director of St. Mary Land & Exploration Company, a publicly traded exploration and production company. From May 2004 through its sale in August 2005, Mr. Sullivan served as a director of Gryphon Exploration

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Company, a privately held exploration and production company. Prior to joining the board of directors of St. Mary Land & Exploration Company and Gryphon Exploration Company, Mr. Sullivan was employed in various capacities by Anadarko Petroleum Corporation from 1981 to August 2003, most recently as Executive Vice President, Exploration and Production (from August 2001 through August 2003). From June 15, 2005 to August 5, 2005, Mr. Sullivan was president and CEO of Leor Energy L.P., a privately held exploration and production company. Mr. Sullivan has a Bachelor of Science in Mechanical Engineering, with high honors, from Texas A&M University.
      S. Wil VanLoh, Jr. is a member of the board of directors of our general partner and has served in such capacity since our founding in October 2005. Since 1997, Mr. VanLoh has been a Managing Partner of Quantum Energy Partners, a private equity fund specializing in the energy industry. Prior to co-founding Quantum Energy Partners in 1997, Mr. VanLoh co-founded Windrock Capital, Ltd., an energy investment banking firm specializing in raising private equity and providing merger, acquisition and divestiture advice for energy companies. Before co-founding Windrock Capital, Ltd. in 1994, Mr. VanLoh was an investment banker in Kidder, Peabody & Co.’s Natural Resources Group and also with NationsBank Investment Banking where he worked on corporate debt and equity financings, mergers and acquisitions, and other highly structured transactions for energy and energy-related companies. Mr. VanLoh currently serves on the boards of Chalker Energy Partners, LP, Denali Oil & Gas Partners, LP, Denali Oil & Gas Partners II, LP, EnergyQuest Resources, LP, Ensight III Energy Partners, LP, Meritage Energy Partners II, LLC, Northpoint Energy Ltd., Rockford Energy Partners II, LLC, Sabretooth Energy Corp., Tecton Energy, LLC, and Tri-C Oil & Gas, LP, all of which are private energy companies. Mr. VanLoh currently serves as a board member and treasurer of the Houston Producers Forum and a member of the IPAA Finance Committee. Mr. VanLoh has a Bachelor of Science in Finance from Texas Christian University.
      Kyle D. Vann was appointed to the board of directors of our general partner upon completion of our private equity offering on March 15, 2006. From 1979 through December 2004 Mr. Vann was employed by Koch Industries most recently serving as Chief Executive Officer of Entergy — Koch, LP, an energy trading and transportation company, from its inception in February 2001 through its sale at year end 2004. Mr. Vann continues to serve Entergy as a consultant and serves on the board of Texon, LP, a private petroleum transportation company. On May 8, 2006, Mr. Vann was appointed to the board of directors of Crosstex Energy, L.P., a publicly traded midstream master limited partnership. Mr. Vann has a Bachelor of Science in Chemical Engineering from the University of Kansas.
Reimbursement of Expenses of Our General Partner
      Our general partner will not receive any management fee or other compensation for its management of us. Our general partner and its affiliates will, however, be reimbursed for all expenses incurred on our behalf. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed.
Executive Compensation
      Our general partner manages our operations and activities through its board of directors and executive officers. We will reimburse our general partner for direct and indirect general and administrative expenses incurred on our behalf, including the compensation of our general partner’s board of directors and executive officers. Our general partner has not incurred any reimbursable expenses related to the compensation of our general partner’s executive officers for their management of us. Currently our general partner’s executive officers are employed by our wholly owned subsidiary, Legacy Reserves Services, Inc., and are directly compensated for their management of us pursuant to their employment agreements.
Employment Agreements
      We and our wholly owned subsidiary Legacy Reserves Services, Inc. have entered into employment agreements, having no fixed termination dates, with each of Messrs. Cary D. Brown, Steven H. Pruett,

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Kyle A. McGraw, Paul T. Horne and William M. Morris. The employment agreements became effective on March 15, 2006. The respective employment agreements of Messrs. Brown, Pruett, McGraw, Horne and Morris provide for an annual base salary of $200,000, $175,000, $150,000, $150,000 and $125,000, respectively subject to an annual increase. The board of directors of our general partner approved an increase in Mr. Morris’ annual base salary to $150,000 effective as of May 1, 2006. Each of the employment agreements also provide for incentive compensation to be paid at the discretion of the board of directors of our general partner. Additionally, on March 15, 2006, Mr. Morris was granted 35,077 restricted units under our Long-Term Incentive Plan pursuant to his employment agreement. The restricted units shall vest one-third each year over three years following the grant date. Mr. Morris’ restricted unit award is also subject to accelerated vesting under certain conditions.
      In the event that we terminate the employment of any of Messrs. Brown, Pruett, McGraw, Horne or Morris, other than for “cause,” or if any of them terminates their employment for “good reason” prior to the occurrence of a change of control or more than one year following a change of control he will be entitled to:
  •  24 monthly payments equal to one-twelfth of his annual salary either (i) as then in effect, if the termination occurs in the first twelve months following the effective date of the employment agreement; or (ii) the highest base salary in effect at any time during the 36 months prior to the date of termination, if the termination occurs after the first twelve months following the effective date of the employment agreement, plus the average annual bonus of the two prior years (or applicable lesser period);
 
  •  a pro rata portion of any bonus for the fiscal year in which termination occurs; and
 
  •  the cost of COBRA continuation coverage during the applicable COBRA period.
      If within one year following a change of control we terminate the employment of any of Messrs. Brown, Pruett, McGraw, Horne or Morris, other than for “cause,” or if any of them terminates their employment for “good reason,” then in lieu of the above severance we will pay the same severance benefits as set forth above, except that the amount set forth in the first bullet above shall be equal to 36 monthly payments and will be paid in a lump sum, plus their average annual bonus of the two prior years (or applicable lesser period). In addition, Messrs. Brown and McGraw would have the right to exercise one demand registration right each. Please read “Registration Rights — Founders Registration Rights Agreement.”
      Generally the employment agreements prohibit each of Messrs. Brown, Pruett, McGraw, Horne and Morris from:
  •  competing with us during the term of his employment unless such competitive activity is approved in writing by a majority of the independent directors of our general partner’s board of directors;
 
  •  soliciting any of our employees or customers for two years following his termination;
 
  •  competing with us in any county in, or adjacent to, a county in which we own oil and natural gas interests or conduct operations on the termination date, or in which we have owned oil and natural gas interests or conducted operations at any time during the six months prior to the termination date, unless such competitive activity is approved in writing by a majority of the independent directors of our general partner’s board, for 90 days following his termination; and
 
  •  from engaging in or participating in any publicly traded limited partnership or limited liability company or privately held company contemplating an initial public offering as a limited partnership or a limited liability company that is in direct competition with us for one year following his termination.
      The non-compete provisions will not apply to the investments held by each of Messrs. Brown, Pruett, McGraw, Horne and Morris prior to the effective date of their employment agreements provided that the investments were identified in their respective agreement. In addition, the non-compete provisions will not apply if we terminate their employment within one year following a change of control.

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Compensation of Directors
      Officers or employees of our general partner and its affiliates who also serve as directors of our general partner will not receive additional compensation. Each non-employee director and independent director has received a grant of 1,750 units effective upon appointment to the board of directors of our general partner and will receive a grant of 1,250 units on the anniversary date of such director’s appointment to the board. Each non-employee director and independent director will also be entitled to receive an annual retainer of $25,000 and up to $1,000 for each board of directors and committee meeting in excess of four per year. The chairman of the Audit Committee is paid an additional $10,000 per year and the chairmen of the Conflicts Committee and the Compensation Committee are each paid an additional $5,000 per year. In addition, each non-employee director and independent director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.
Long-Term Incentive Plan
      General. We adopted the Legacy Reserves LP Long-Term Incentive Plan for the employees, consultants and directors of us, our affiliates and our general partner. The awards under the long-term incentive plan may include unit grants, restricted units, phantom units, unit options and unit appreciation rights. The long-term incentive plan permits the grant of awards covering an aggregate of 2,000,000 units. As of November 10, 2006 grants of awards covering 386,866 units have been made. The plan is administered by the compensation committee of the board of directors of our general partner.
      Our general partner’s board of directors, or its compensation committee, in its discretion may terminate, suspend or discontinue the long-term incentive plan at any time with respect to any award that has not yet been granted. Our general partner’s board of directors, or its compensation committee, also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
      Unit Grants. The long-term incentive plan permits the grant of units. A unit grant is a grant of units that vests immediately upon issuance.
      Restricted Units and Phantom Units. A restricted unit is a unit that is subject to forfeiture prior to the vesting of the award. A phantom unit is a notional unit that entitles the grantee to receive a unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a unit. The compensation committee may make grants under the plan of restricted units and phantom units to employees, consultants and directors containing such terms, consistent with the plan, as the compensation committee shall determine. The compensation committee will determine the period over which restricted units and phantom units granted to employees, consultants and directors will vest. The committee may base vesting upon the achievement of specified financial objectives or on the grantee’s completion of a period of service. In addition, the restricted units and phantom units will vest upon a change of control of Legacy Reserves LP or our general partner, unless provided otherwise by the compensation committee in the award agreement.
      If a grantee’s employment, service relationship or membership on the board of directors terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise in the award agreement or waives (in whole or in part) any such forfeiture. Units to be delivered in connection with the grant of restricted units or upon the vesting of phantom units may be units acquired by us on the open market, or from any other person or we may issue new units, or any combination of the foregoing. Our general partner is entitled to reimbursement by us for the cost incurred in acquiring units. Thus, the cost of the restricted units and delivery of units upon the vesting of phantom units will be borne by us. If we issue new units in connection with the grant of restricted units or upon vesting of the phantom units, the total number of units outstanding will increase. The compensation committee, in its discretion, may provide for tandem distribution rights with respect to restricted units and grant tandem distribution equivalent rights with respect to phantom units that entitle the

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holder to receive cash equal to any cash distributions made on units prior to the vesting of a restricted or phantom unit.
      Unit Options and Unit Appreciation Rights. The long-term incentive plan permits the grant of options covering units and the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. Such excess may be paid in units, cash, or a combination thereof, as determined by the compensation committee in its discretion. The compensation committee will be able to make grants of unit options and unit appreciation rights under the plan to employees, consultants and directors containing such terms as the committee shall determine consistent with the plan. Unit options and unit appreciation rights may not have an exercise price that is less than the fair market value of the units on the date of grant. In general, unit options and unit appreciation rights granted will become exercisable over a period determined by the compensation committee. In addition, the unit options and unit appreciation rights will become exercisable upon a change in control of Legacy Reserves LP or our general partner, unless provided otherwise by the committee in the award agreement. The compensation committee, in its discretion may grant tandem distribution equivalent rights with respect to unit options and unit appreciation rights.
      Upon exercise of a unit option (or a unit appreciation right settled in units), we will acquire units on the open market or from any other person or we may issue new units, or any combination of the foregoing. If we issue new units upon exercise of the unit options (or a unit appreciation right settled in units), the total number of units outstanding will increase, and our general partner will pay us the proceeds it receives from an optionee upon exercise of a unit option. The availability of unit options and unit appreciation rights is intended to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of unitholders.
401(k) Plan
      We maintain a 401(k) plan. The plan permits eligible employees to make voluntary, pre-tax contributions to the plan up to a specified percentage of compensation, subject to applicable tax limitations. We may make a discretionary matching contribution to the plan for each eligible employee equal to 4.0% of an employee’s annual compensation not in excess of $220,000 for 2006, subject to applicable tax limitations. Eligible employees who elect to participate in the plan are generally vested in any matching contribution after commencement of employment with the company. The plan is intended to be qualified under Section 401(a) of the Internal Revenue Code so that contributions to the plan, and income earned on plan contributions, are not taxable to employees until withdrawn from the plan, and so that contributions, if any, will be deductible when made.

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SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
      The following table sets forth the beneficial ownership of our units held by:
  •  each person known by us to be a beneficial owner of 5% or more of our outstanding units;
 
  •  each of the directors of our general partner;
 
  •  each named executive officer of our general partner; and
 
  •  all directors and executive officers of our general partner as a group.
      The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities, and a person may be deemed a beneficial owner of securities as to which he has no economic interest.
      Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Mr. VanLoh’s address is 777 Walker Street, Suite 2530, Houston, Texas 77002, and the business address for the other beneficial owners listed below is 303 W. Wall Street, Suite 1600, Midland, Texas 79701.
                   
    Units to be Beneficially
    Owned After the Offering
     
Name of Beneficial Owner   Number   Percentage
         
 
Moriah Group(a)(b)
     7,289,999       39.8 %
 
Moriah Properties, Ltd.(a)
     6,747,718       36.8  
 
Brothers Group(a)(c)
     4,189,525       22.9  
 
Brothers Production Properties, Ltd.(a)
     3,381,780       18.5  
 
Brothers Production Company, Inc.(a)(d)
     3,561,661       19.4  
 
MBN Properties LP
     3,162,438       17.3  
 
Newstone Group(a)
     1,638,861       9.0  
Directors and Officers
                
 
Dale A. Brown(a)(e)(f)
     7,291,749       39.8  
 
Cary D. Brown(a)(g)
     6,747,718       36.8  
 
Kyle A. McGraw
     —       —  
 
S. Wil VanLoh, Jr.(a)(e)(h)(i)
     917,630       5.0  
 
Kyle D. Vann(e)
     1,750       *  
 
William D. Sullivan(e)
     1,750       *  
 
G. Larry Lawrence(e)
     1,750       *  
 
Steven H. Pruett(a)(h)(j)
     296,935       1.6  
 
Paul T. Horne(a)(k)
     121,683       *  
 
William M. Morris(l)
     —       —  
 
All directors and executive officers as a group (10 persons)
     8,633,247       46.8  
 
 * Percentage of units beneficially owned does not exceed (1%).
(a) Assumes that the units held by MBN Properties LP will be distributed to the partners of MBN Properties LP, including Moriah Properties, Ltd., Brothers Production Properties, Ltd., Brothers

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Production Company, Inc., the Newstone Group, SHP Capital LP, DAB Resources, Ltd. and H2K Holdings, Ltd. as follows:

           
Entity   Number
     
Moriah Properties, Ltd. 
     884,175  
Brothers Production Properties, Ltd. 
     457,968  
Brothers Production Company, Inc. 
     24,360  
Brothers Operating Company, Inc. 
     4,872  
Newstone Group
     1,447,157  
SHP Capital LP
     191,704  
DAB Resources, Ltd. 
     27,330  
H2K Holdings, Ltd. 
     70,943  
J&W McGraw Properties, Ltd. 
     53,929  
       
 
Total
     3,162,438  
       
(b) Includes units held by Moriah Properties, Ltd. as well as 542,281 units held by DAB Resources, Ltd., assuming that the units held by MBN Properties LP are distributed to partners of MBN Properties LP as described in footnote (a) above.
 
(c) Includes units held by Brothers Production Properties, Ltd. and Brothers Production Company, Inc. as well as 35,976 units held by Brothers Operating Company, Inc. and 591,887 units held by J&W McGraw Properties, Ltd., assuming that the units held by MBN Properties LP are distributed to partners of MBN Properties LP as described in footnote (a) above.
 
(d) Brothers Production Company, Inc., in its capacity as general partner of Brothers Production Properties, Ltd. is deemed to beneficially own the partnership interests in us held by Brothers Production Properties, Ltd. as well as 179,882 units it holds directly, assuming that the units held by MBN Properties LP are distributed to partners of MBN Properties LP as described in footnote (a) above.
 
(e) Includes 1,750 units granted under the Legacy Reserves LP Long-Term Incentive Plan to each non-employee director.
 
(f) Mr. Dale A. Brown is deemed to beneficially own the partnership interests in us held by Moriah Properties, Ltd. as well as 542,281 units held by DAB Resources, Ltd., assuming that the units held by MBN Properties LP are distributed to partners of MBN Properties LP as described in footnote (a) above. Mr. Dale A. Brown and Mr. Cary D. Brown share voting and investment power with respect to the partnership interests in us held by Moriah Properties, Ltd.
 
(g) Mr. Cary D. Brown is deemed to beneficially own the partnership interests in us held by Moriah Properties, Ltd. Mr. Dale A. Brown and Mr. Cary D. Brown share voting and investment power with respect to the partnership interests in us held by Moriah Properties, Ltd.
 
(h) Assumes that the units beneficially owned by the Newstone Group will be distributed to the members of the Newstone Group, including entities controlled by Mr. VanLoh and Mr. Pruett as follows:
           
Entity   Number
     
Blackstone Investments I, Ltd. 
     388,458  
Blackstone Investments II, Ltd. 
     142,819  
Newstone Capital, LP
     239,372  
SHP Capital LP
     105,231  
Trinity Equity Partners I, LP
     571,277  
       
 
Total
     1,447,157  
       
(i) Mr. VanLoh is deemed to beneficially own the units held by Newstone Capital, LP, Trinity Equity Partners I, LP and 105,231 units held by SHP Capital, LP, assuming that the units held by MBN Properties LP are distributed to the partners of MBN Properties LP as described in footnote (a) above and that the units beneficially owned by the Newstone Group will be distributed to the members of the Newstone Group as described in footnote (h) above.

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(j) Mr. Pruett is deemed to beneficially own the 296,935 units held by SHP Capital L.P., assuming that the units held by MBN Properties LP are distributed to partners of MBN Properties LP as described in footnote (a) above.
 
(k) Mr. Horne is deemed to beneficially own the 121,683 units held by H2K Holdings, Ltd., assuming that the units held by MBN Properties LP are distributed to partners of MBN Properties LP as described in footnote (a) above.
 
(l) Mr. Morris was granted 35,077 restricted units upon the closing of our private equity offering, subject to vesting. Please read “Management — Employment Agreements.”
      The following table sets forth the beneficial ownership of equity interests of Legacy Reserves GP, LLC by the directors and each named executive officer of our general partner:
         
Name of Beneficial Owner   Equity Interest
     
Dale A. Brown(a)(b)
     54.9 %
Cary D. Brown(b)(c)
     50.5  
Kyle A. McGraw
     —  
S. Wil VanLoh, Jr.(d)
     6.1  
Steven H. Pruett(d)
     1.5  
Kyle D. Vann
     —  
William D. Sullivan
     —  
G. Larry Lawrence
     —  
Paul T. Horne
     0.4  
William M. Morris
     —  
All directors and executive officers as a group (10 persons)
     62.9  
 
(a) Assumes that the equity interests held by MBN Properties LP will be distributed to the partners of MBN Properties LP, including Moriah Properties, Ltd., Brothers Production Properties, Ltd., Brothers Production Company, Inc. and the Newstone Group.
 
(b) Includes a 44.5% equity interest held by Moriah Properties, Ltd. and a 4.0% equity interest held by DAB Resources, Ltd.
 
(c) Includes a 44.5% equity interest held by Moriah Properties, Ltd.
 
(d) Assumes that the equity interests beneficially owned by the Newstone Group will be distributed to the members of the Newstone Group, including entities controlled by Mr. VanLoh and Mr. Pruett.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
      Our Founding Investors including members of our management and directors, own an aggregate of 13,313,934 units, representing a 72% limited partner interest in us. In addition, our general partner owns an approximate 0.1% general partner interest in us.
Distributions and Payments to Our General Partner and Its Affiliates
      The following table summarizes the distributions and payments made or to be made by us to our general partner and our Founding Investors in connection with our formation, ongoing operation and any liquidation of Legacy Reserves LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Distributions of available cash to our general partner and our Founding Investors We will generally make cash distributions 99.9% to the unitholders pro rata, including our Founding Investors, as the holders of an aggregate of 13,313,934 units, and approximately 0.1% to our general partner.
 
Assuming we have sufficient available cash to pay the full amount of our current quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of approximately $30,065 on its approximate 0.1% general partner interest, and our Founding Investors would receive approximately $21.8 million on their units.
 
Payments to our general partner Our general partner will be entitled to reimbursement for all expenses it incurs on our behalf. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. Please read “The Partnership Agreement — Reimbursement of Expenses.”
 
Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest will either be sold to the new general partner for cash or converted into units, for an amount equal to the fair market value of that interest. Please read “The Partnership Agreement — Withdrawal or Removal of the General Partner.”
Distribution Upon Liquidation
Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances. Please read “How We Make Cash Distributions.”
Agreements Governing the Transactions
      We and other partners have entered into the various documents and agreements that effected the private equity offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of the private equity offering. These agreements, including the Omnibus Agreement described below, were not the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not have been effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the

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transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, were paid from the proceeds of the private equity offering.
Omnibus Agreement
      On March 15, 2006, we entered into an agreement with our Founding Investors and certain of their affiliates. The agreement, which we refer to as the Omnibus Agreement, set forth the overall agreement of the parties with respect to the formation transactions among the parties and included:
  •  the contribution of assets by the Founding Investors and the units to be issued in exchange therefor pursuant to a Contribution, Conveyance and Assumption Agreement;
 
  •  the granting of registration rights to the Founding Investors pursuant to the Founders Registration Rights Agreement described below;
 
  •  the agreement of the Founding Investors to vote for two individuals designated by the Moriah Group, one individual designated by the Brothers Group, and one individual designated by the Newstone Group in the election of directors of our general partner prior to the election of the board of directors by our unitholders; and
 
  •  reimbursement for expenses incurred in connection with our formation.
Founders Registration Rights Agreement
      The Founding Investors and their permitted transferees are entitled to registration rights pursuant to the Founders Registration Rights Agreement. The Founders Registration Rights Agreement gives the beneficiaries thereof certain “demand” and “piggyback” registration rights pursuant to which they will be entitled to cause us to use our commercially reasonable best efforts to register all or a portion of their units and participate in our registration of securities under the Securities Act. Please read “Registration Rights — Founders Registration Rights Agreement.”
Transactions with Executive Officers, Directors and Principal Unitholders
Formation Transactions
      Simultaneously with the completion of the private equity offering, each of the Founding Investors contributed oil and natural gas properties and related assets to us as contemplated by the Omnibus Agreement, and we purchased oil and natural gas properties from MBN Properties LP and the charitable foundations. In consideration for the oil and natural gas properties and related assets, we paid cash in the aggregate amount of approximately $73.0 million and issued an aggregate of 17,640,068 unregistered units.

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      The following table sets forth for each of the Founding Investors and the three charitable foundations the cash and units received pursuant to the formation transactions:
                   
    Cash   Units
         
    (In millions)    
Moriah Group:
                
 
Moriah Properties, Ltd. 
     —       7,334,070  
 
DAB Resources, Ltd. 
     —       859,703  
Brothers Group:
                
 
Brothers Production Properties, Ltd
     —       4,968,945  
 
Brothers Production Company, Inc. 
     —       264,306  
 
Brothers Operating Company, Inc. 
     —       52,861  
 
J&W McGraw Properties, Ltd. 
     —       914,246  
MBN Properties LP
   $ 65.30       3,162,438  
H2K Holdings, Ltd. 
     —       83,499  
Charities Support Foundation, Inc. 
   $ 0.38       —  
Moriah Foundation, Inc. 
   $ 3.65       —  
Cary Brown Family Foundation, Inc. 
   $ 3.65       —  
      In September 2005, MBN Properties LP acquired the PITCO properties for $63.9 million cash ($64.3 million including asset retirement obligations) net of post-closing adjustments. Mr. Cary D. Brown, the Chief Executive Officer and Chairman of the Board of our general partner, Mr. Pruett, the President, Chief Financial Officer and Secretary of our general partner, Mr. Horne, the Vice President-Operations of our general partner, Mr. Dale A. Brown, a member of the board of directors of our general partner, and Mr. VanLoh, a member of the board of our general partner, all indirectly own membership interests in MBN Properties LP.
Petroleum Strategies, Inc.
      Neither Moriah Properties, Ltd. nor its general partner, Moriah Resources, Inc., have any employees. All operational personnel performing services with respect to their properties and business were employees of Petroleum Strategies, Inc., a Qualified Intermediary for like kind exchanges owned by Mr. Dale A. Brown and Mr. Cary D. Brown. The personnel and general administrative services were provided to Moriah Properties, Ltd. under an overhead allocation agreement. During 2005, Moriah Properties, Ltd. and Moriah Resources, Inc., paid $838,899 to Petroleum Strategies, Inc. pursuant to this agreement as reimbursement for salaries and other general and administrative expenses. We have no future obligations for personal and general and administrative services to Petroleum Strategies.
Office Leases
      TCTB Partners, a limited partnership of which Dale A. Brown, Cary D. Brown and Kyle A. McGraw are limited partners, owns the office building in which the principal offices of the Moriah Group, Brothers Group and Petroleum Strategies are located.
      During 2005, the Brothers Group and Moriah Group paid rentals of $46,836 and $35,220, respectively, to TCTB Partners. We assumed the existing leases for 15,000 square feet of office space. The annual rental initially payable to TCTB Partners is $82,056, without respect to property taxes and insurance. We also sublease 3,000 square feet of our space to Petroleum Strategies at the same rate per square foot that we are charged by TCTB Partners.
      In August 2006 we entered in to an additional lease, having an initial five year term with a five year renewal option, with TCTB Partners. We will lease an additional 4,000 square feet during the first year, an additional 10,000 square feet during the second and third years and an additional 20,000 square feet during the fourth and fifth years at a rate of $7.00 per square foot, before property taxes and insurance.

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Other
      Travis McGraw, the brother of Kyle A. McGraw, Executive Vice-President of Business Development and Land and a member of the board of directors of our general partner, is an employee of Legacy serving as our Marketing, Revenue, and Regulatory Reporting Coordinator. We paid Travis McGraw $50,000 as compensation for his services during the nine months ended September 30, 2006. Travis McGraw’s current annual salary is $100,000 plus a discretionary, non-guaranteed bonus. Additionally, during the nine months ended September 30, 2006, we hired Scott McGraw, also the brother of Kyle McGraw, as an independent contractor to perform engineering services. We paid Scott McGraw $32,915 during this time as compensation for his services and expects to pay him an additional $15,000 per quarter for his contract engineering services.
      In order to fund the purchase price and expenses of the PITCO acquisition, MBN Properties LP and MBN Management, LLC borrowed amounts from entities owned and controlled by certain of our officers and directors.
      On July 21, 2005, MBN Properties LP entered into a $6.5 million subordinated loan agreement under which Moriah Properties, Ltd., an entity owned and controlled by Cary D. Brown and Dale A. Brown, contributed $1,648,670, Brothers Production Properties, Ltd., an entity owned a controlled by Kyle A. McGraw, the Executive Vice President of Business Development and Land and member of the board of directors of our general partner, contributed $1,176,330, Newstone Capital, LP and Trinity Equity Partners I, LP, entities owned and controlled by Mr. VanLoh, contributed $65,000 and $186,250, respectively, and SHP Capital LP, an entity owned and controlled by Mr. Pruett, contributed $62,500. The $3,325,000 borrowed under the subordinated loan agreement was used to fund the deposit for the purchase of the PITCO properties.
      On July 22, 2005, MBN Management, LLC entered into a $2 million subordinated loan agreement under which Brothers Production Properties, Ltd. contributed $619,888, Moriah Properties, Ltd. contributed $900,112, Newstone Capital, LP contributed $50,801, Trinity Equity Partners I, LP contributed $141,550 and SHP Capital LP contributed $46,099. MBN Management, LLC borrowed approximately $1.9 million under the subordinated loan agreement to fund expenses related to the PITCO acquisition.
      On September 13, 2005, MBN Properties LP replaced the $6.5 million subordinated loan agreement by entering into a $34 million subordinated loan agreement under which Moriah Properties, Ltd. contributed an additional $17,861,990 and Brothers Production Properties, Ltd. contributed $12,588,030. MBN Properties LP borrowed approximately $33.8 million under the subordinated loan agreement to partially fund the remaining purchase price of the PITCO properties.
      All amounts outstanding under the $2 million and $34 million subordinated loan agreements were repaid in full on March 15, 2006 with proceeds from our private equity offering and borrowings under our $300 million revolving credit facility that we entered into at the closing of our private equity offering.
      On October 23, 2003, Moriah Resources, Inc. purchased from Pecos Production Company a working interest in the Langlie Mattix Penrose Sand Unit located in Lea Country, New Mexico for approximately $2.1 million. On November 19, 2003, Paul T. Horne, our Vice President of Operations, purchased from Moriah Resources, Inc. a working interest in the Langlie Mattix Penrose Sand Unit. As part of the transaction, Mr. Horne received a 5% back-in-after-payout from Moriah Resources, Inc. In December 2005, Moriah Resources, Inc. purchased the 5% back-in-after-payout from Mr. Horne for approximately $331,040.

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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 our Founding Investors), on the one hand, and our partnership 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. 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 or any other partner, 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 the unitholders. Our partnership agreement also restricts the remedies available to 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 the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:
  •  approved by the conflicts committee, although our general partner is not obligated to seek such approval;
 
  •  approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner or any of its affiliates;
 
  •  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
  •  fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
      Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our general partner. 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 third and 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 the partnership, 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 that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership. Please read “Management — Management of Legacy Reserves LP” for information about the conflicts committee of the board of directors of our general partner.
      Conflicts of interest could arise in the situations described below, among others.
Certain of our general partner’s affiliates may engage in competition with us.
      Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner, other than our executive officers and their affiliates, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to the general partner and its affiliates, other than our executive officers and their affiliates. As a result, neither the general partner nor any of its affiliates other than our executive officers and their affiliates, will have any obligation to present business opportunities to us.

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Our general partner is allowed to take into account the interests of parties other than us, such as its owners and their affiliates, 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 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, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.
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 the limitations, might constitute breaches of fiduciary duty.
      In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
  •  provides that the general partner shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of our partnership;
 
  •  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 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 be “fair and reasonable” to us, as determined by the board of directors of our general partner in good faith, and that, 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; and
 
  •  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees 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 those other persons acted in bad faith or engaged in fraud or willful misconduct.
Actions taken by our general partner may 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:
  •  the amount and timing of asset purchases and sales;
 
  •  cash expenditures;
 
  •  borrowings;
 
  •  the issuance of additional units; and
 
  •  the creation, reduction or increase of reserves in any quarter.
Our general partner determines which costs incurred by it are reimbursable by us.
      We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.

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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.
      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 does not intend to charge us a management fee. Our general partner may also enter into additional contractual arrangements with any of its 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 and its affiliates, on the other hand, are or will be the result of arm’s-length negotiations.
      Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the units offered in this offering.
      Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.
Our general partner intends to limit its liability regarding our obligations.
      Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability or our 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.
Unitholders will 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 and its 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 and its affiliates in our favor.
Our general partner may exercise its right to call and purchase units if it and its affiliates own more than 80% of the units.
      If at any time our general partner and its affiliates own more than 80% of our units, our general partner may exercise its right to call and purchase units as provided in the 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 unitholder may have his units purchased from him at an undesirable time or price. Our general partner and its affiliates, including members of our management, own an aggregate of 72% of our outstanding units. Please read “The Partnership Agreement — Limited Call Right.”
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 regarding this offering have been retained by our general partner, its affiliates and us and may continue to be retained by our general partner, its affiliates and us after the offering. Attorneys, independent accountants and others who will perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of 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 units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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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:
  •  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 securities of the partnership, and the incurring of any other obligations;
 
  •  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;
 
  •  the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person;
 
  •  the negotiation, execution and performance of any contracts, conveyances or other instruments;
 
  •  the distribution of partnership cash;
 
  •  the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
 
  •  the maintenance of insurance for our benefit and the benefit of our partners;
 
  •  the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;
 
  •  the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;
 
  •  the indemnification of any person against liabilities and contingencies to the extent permitted by law;
 
  •  the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities; and
 
  •  the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.
      Our 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 believe that the determination is in our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.
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 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 allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law

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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 have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration 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 the 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.
 
Partnership agreement modified standards Our partnership agreement contains provisions pursuant to which limited partners waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to 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.
 
Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a 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 its board of directors determines that the resolution or course of action taken with respect to the conflict of interest

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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 the partnership, 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.
 
In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us, our limited partners or assignees 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.
 
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. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. 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.

      By purchasing our units, each unitholder automatically agrees to be bound by the provisions in the 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 or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.
      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 UNITS
The Units
      The units represent partnership interests in us. The holders of units are entitled to participate in 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 units in and to distributions, please read this section and “Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”
Transfer Agent and Registrar
Duties
      Computershare Trust Company, N.A. serves as registrar and transfer agent for the units. We pay all fees charged by the transfer agent for transfers of units, except the following fees that will be paid by unitholders:
  •  surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
 
  •  special charges for services requested by a holder of a unit; and
 
  •  other similar fees or charges.
      There will be no charge to holders for disbursements of our cash distributions. We will indemnify the transfer agent against all claims and losses that may arise out of all actions of the transfer agent or its agents or subcontractors for their activities in that capacity, except for any liability due to any gross negligence or willful misconduct of the transfer agent or subcontractors.
Resignation or Renewal
      The transfer agent may at any time 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 has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner is authorized to act as the transfer agent and registrar until a successor is appointed.
Transfer of Units
      By transfer of units in accordance with our partnership agreement, each transferee of units shall be admitted as a limited partner with respect to the units transferred when such transfer and admission is reflected on our books and records. Additionally, each transferee of units:
  •  becomes the record holder of the units;
 
  •  represents that the transferee has the capacity, power and authority to enter into the partnership agreement;
 
  •  automatically agrees to be bound by the terms and conditions of, and is deemed to have executed our partnership agreement; and
 
  •  gives the consents, approvals and waivers contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.
      A transferee will become a substituted limited partner of our partnership for the transferred 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.

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      We may, at our discretion, treat the nominee holder of a unit as the absolute owner. In that case, the beneficial holder’s rights are limited to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
      Units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred units.
      Until a unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, 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.
Non-Citizen Assignees; Redemption
      For a discussion of our general partner’s ability to redeem the units held by persons other than U.S. citizens, please read “The Partnership Agreement — Non-Citizen Assignees; Redemption.”

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THE PARTNERSHIP AGREEMENT
      The following is a summary of the material provisions of our partnership agreement. Our partnership agreement is included in this prospectus as Appendix A.
      We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
  •  with regard to distributions of available cash, please read “Cash Distribution Policy and Restrictions on Distributions” and “How We Make Cash Distributions”;
 
  •  with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;
 
  •  with regard to the transfer of units, please read “Description of the Units — Transfer of Units”; and
 
  •  with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”
Organization and Duration
      We were organized in October 2005 and will have a perpetual existence.
Purpose
      Our purpose under the partnership agreement is to engage in any business activities that are approved by our general partner. Our general partner, however, may not cause us to engage in any business activities that it determines would cause us to be treated as a corporation for federal income tax purposes. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.
Power of Attorney
      Each limited partner, and each person who acquires a unit from a unitholder, by accepting the unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney, among other things, to execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to grant consents and waivers on behalf of the limited partners under, our partnership agreement. Please read “— Amendment of the Partnership Agreement” below.
Capital Contributions
      Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”
Voting Rights
      The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require the approval of a majority of the units.
      In voting their 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.
 
Amendment of the partnership agreement Certain amendments may be made by our general partner without the approval of our unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.”

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Merger of our partnership or the sale of all or substantially all of our assets Unit majority in certain circumstances. Please read “— Merger, Sale or Other Disposition of Assets.”
 
Amendment of the limited partnership agreement of our operating partnership and other action taken by us as the sole member of its general partner Unit majority if such amendment or other action would adversely affect our limited partners in any material respect. Please read “— Amendment of the Partnership Agreement — Action Relating to the Operating Partnership.”
 
Dissolution of our partnership Unit majority. Please read “— Termination and Dissolution.”
 
Continuation of our partnership upon dissolution Unit majority. Please read “— Termination and Dissolution.”
 
Withdrawal of our general partner Under most circumstances, the approval of a unit majority, excluding units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to March 31, 2016 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of our General Partner.”
 
Removal of the general partner Not less than 662/3% of our outstanding units, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner.”
 
Transfer of the general partner
interest		 Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person 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 units, excluding units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to March 31, 2016. Please read “— Transfer of General Partner Interest.”
 
Transfer of ownership interests in our general partner No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner.
Limited Liability
Participation in the Control of Our Partnership
      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 the 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 units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:
  •  to remove or replace the general partner;
 
  •  to approve some amendments to the partnership agreement; or
 
  •  to take other action under the partnership agreement;

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constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the 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.
Unlawful Partnership Distribution
      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. 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 the transferring limited partner 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.
Failure to Comply with the Limited Liability Provisions of Jurisdictions in Which We Do Business
      Our subsidiaries may be deemed to conduct business in Mississippi, New Mexico, Oklahoma and Texas. Our subsidiaries may conduct business in other states in the future. Maintenance of our limited liability as a limited partner of our operating partnership may require compliance with legal requirements in the jurisdictions in which the operating partnership conducts business, including qualifying our 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 limited partner interest in the operating partnership 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 the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the 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 the unitholders.
      It is possible that we will fund acquisitions through the issuance of additional units or other partnership securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of units in our distributions of available cash. In addition, the issuance of additional units or other partnership securities may dilute the value of the interests of the then-existing unitholders in our net assets.

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      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 voting rights to which the units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities that may effectively rank senior to the units.
      Upon issuance of additional partnership securities, our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its initial 0.1% general partner interest in us. Since our private equity offering and the related formatting transactions our general partner has not elected to make additional capital contributions to maintain its 0.1% general partner interest in us. Our general partner’s initial 0.1% interest in us has been, and will continue to be reduced, if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. 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 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 percentage interest of the general partner and its affiliates, including such interest represented by units that existed immediately prior to each issuance. Unitholders will not have preemptive rights to acquire additional 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. Our general partner, however, will have 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 the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the 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:
  •  enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
 
  •  enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.
      The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can only be amended upon the approval of the holders of at least 90% of the outstanding units voting together at a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, affiliates of our general partner, including members of our management, will continue to own an aggregate of 72% of our outstanding units.
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:
  •  change in our name, the location of our principal place of business, our registered agent or our registered office;

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  •  the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
 
  •  a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
 
  •  an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees 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;
 
  •  an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities;
 
  •  any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
 
  •  an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
 
  •  any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;
 
  •  a change in our fiscal year or taxable year and related changes;
 
  •  certain mergers or conveyances as set forth in our partnership agreement; or
 
  •  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 or transferee in connection with a merger or consolidation approved in connection with our partnership agreement, or if our general partner determines that those amendments:
  •  do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;
 
  •  are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
 
  •  are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;
 
  •  are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
 
  •  are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
Opinion of Counsel and Unitholder Approval
      Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described under “— No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of

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holders of at least 90% of the outstanding units voting as a single class 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 will require 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 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.
Action Relating to the Operating Partnership and its General Partner
      Without the approval of the holders of units representing a unit majority, our general partner is prohibited from consenting on our behalf, as the sole limited partner of the operating partnership, and the sole member of its general partner, to any amendment to the limited partnership agreement or limited liability company agreement of either such entities or taking any action on our behalf permitted to be taken by a limited partner of the operating partnership or a member of its general partner, in each case, that would adversely effect our limited partners (or any particular class of limited partners) in any material respect.
Merger, Sale or Other Disposition of Assets
      A merger or consolidation of us requires the prior consent of our general partner. Our general partner, however, will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the 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, among other things, to 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 approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets 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 that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, the transaction would not result in an amendment to our partnership agreement that could not otherwise be adopted solely by our general partner, each of our units will be an identical unit of our partnership following the transaction, and the units to be issued do not exceed 20% of our outstanding units immediately prior to the transaction.
      If the conditions specified in the 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 all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under the 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 transaction or event.
Termination and Dissolution
      We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:
  •  the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
 
  •  there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

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  •  the entry of a decree of judicial dissolution of our partnership; or
 
  •  the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.
      Upon a dissolution under the last bullet point 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 the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:
  •  the action would not result in the loss of limited liability of any limited partner; and
 
  •  none of us, our operating partnership or any of our other 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.
Liquidation and Distribution of Proceeds
      Upon our dissolution, unless we are reconstituted and 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 to liquidate our assets and apply the proceeds of the liquidation as provided in “How We Make 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 the General Partner
      Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to March 31, 2016 without obtaining the approval of the holders of at least a majority of the outstanding units, excluding units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after March 31, 2016, our general partner may withdraw as 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 without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the 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 Interest.”
      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 unit majority may select a successor to that 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 after that withdrawal, the holders of a unit majority 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 662/3% of the outstanding units, voting together as a single class, 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 the outstanding units. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. Affiliates of our general partner, including members of our management, own an aggregate of 72% of our outstanding units.

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      Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist or our general partner withdraws where that withdrawal does not violate our partnership agreement, our general partner will have the right to convert its general partner interest into units or to receive cash in exchange for such interest based on the fair market value of its interest at that time.
      In the event of removal of such a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest for a cash payment equal to the fair market value of such interest. Under all other circumstances where a 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 general partner interest of the departing general partner for 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. Or, if the departing general partner 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 will automatically convert into units equal to the fair market value of those interests as determined by 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 Interest
      Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:
  •  an affiliate of our general partner (other than an individual); or
 
  •  another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,
our general partner may not transfer all or any part of its general partner interest in our partnership to another person prior to March 31, 2016 without the approval of the holders of at least a majority of the outstanding units, excluding 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 units to one or more persons without unitholder approval.
Transfer of Ownership Interests in the General Partner
      At any time, the members of our general partner may sell or transfer all or part of their membership interest in our general partner to an affiliate or 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 our management. If any person or group

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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 voting rights on all of its units. This loss of 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 85% of the 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 remaining partnership securities 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:
  •  the highest cash price paid by either of our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
 
  •  the current market price as of the date three days before the date the notice is mailed.
      As a result of our general partner’s right to purchase outstanding partnership securities, a holder of partnership securities may have his partnership securities purchased at an undesirable time or price. Our partnership agreement provides that the resolution of any conflict of interest that is fair and reasonable will not be a breach of the partnership agreement. Our general partner may, but is not obligated to, submit the conflict of interest represented by the exercise of the limited call right to the conflicts committee for approval or seek a fairness opinion from an investment banker. If our general partner exercises its limited call right, it will make a determination at the time, based on the facts and circumstances, and upon the advice of counsel, as to the appropriate method of determining the fairness and reasonableness of the transaction. Our general partner is not obligated to obtain a fairness opinion regarding the value of the units to be repurchased by it upon exercise of the limited call right.
      There is no restriction in our partnership agreement that prevents our general partner from issuing additional units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934.
      The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read “Material Tax Consequences — Disposition of Units.”
Meetings; Voting
      Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or transferees who are 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. Units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the units will not be voted, except that, in the case of units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those 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 until after the closing of an initial public offering of our units, if any, occurs or until our Founding Investors own less than 50% of our outstanding units. It is anticipated that such a meeting would be called for the express purpose of electing the members of the board of directors of our general partner. The limited liability agreement of our general partner provides for a seven member board of directors. Prior to the closing of an initial public offering, defined in our partnership agreement as a public offering of our units generating gross proceeds of

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not less than $20 million that results in our units being traded on a national securities exchange or the Nasdaq Stock Market, all of the directors of our general partner will be elected by its owners (currently our Founding Investors) and not by our unitholders, except in the following circumstances:
  •  if the owners of our general partner own less than 50% but at least 35% of our units, the unitholders, including the general partner and its affiliates, will be entitled to elect three of the seven directors;
 
  •  if the owners of our general partner own less than 35% but at least 20% of our units the unitholders, including the general partner and its affiliates, will be entitled to elect five of the seven directors; and
 
  •  if the owners of our general partner own less than 20% of our units the unitholders, including the general partner and its affiliates, will be entitled to elect all of the directors.
      Following an initial public offering of our units, our unitholders, including the general partner and its affiliates, will be entitled to elect all of the directors of our general partner.
      Additionally, 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.
      Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special 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 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. 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 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 units in accordance with our partnership agreement, each transferee of units shall be admitted as a limited partner with respect to the units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability,” the 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, our general partner may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner 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

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our general partner determines after receipt of the information that the limited partner is not an eligible citizen, our general partner may elect to treat the limited partner 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.
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:
  •  our general partner;
 
  •  any departing general partner;
 
  •  any person who is or was an affiliate of a general partner or any departing general partner;
 
  •  any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;
 
  •  any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and
 
  •  any person designated by our general partner.
      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 loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against 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 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. The general partner is entitled to determine in good faith the expenses that are allocable to us.
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 tax and financial reporting purposes, our fiscal year is the calendar year.
      We will furnish or make available to record holders of units, within 120 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 public accountants. Except for our fourth quarter, we will also furnish summary financial information within 90 days after the close of each quarter.
      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 unitholders will depend on the cooperation of 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.

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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 demand and at his own expense, have furnished to him:
  •  a current list of the name and last known address of each partner;
 
  •  a copy of our tax returns;
 
  •  information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;
 
  •  copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;
 
  •  information regarding the status of our business and financial condition; and
 
  •  any other information regarding our affairs as is just and reasonable.
      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.

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REGISTRATION RIGHTS
Shelf Registration Statement
      We entered into a registration rights agreement in connection with the private equity offering. In the registration rights agreement we agreed, at our expense, to use our reasonable best efforts to file with the SEC (which occurred on May 12, 2006 pursuant to the filing of shelf registration statements) no later than May 15, 2006 a shelf registration statement for FBR and certain of its affiliates and a registration statement for the other purchasers registering for resale the units sold in this offering plus any additional units issued in respect thereof whether by unit dividend, unit split or otherwise.
      If the shelf registration statements have not become effective within 180 days of their filing, until they are effective, we will pay to the beneficiaries of the registration rights agreement affected by the failure a penalty equivalent to a 0.5% increase in the yield implied from the offering price and our initial quarterly distribution on an annualized basis. Based on an offering price of $17.00 per unit and an initial quarterly distribution of $1.64 per unit on an annualized basis, this penalty will be $0.02125 per unit per quarter, or $0.085 per unit on an annualized basis. The requirement that the shelf registration statements be effective within 180 days of their filing may be delayed by up to 60 days upon a determination of the independent members of our general partner’s board of directors that such delay is required due to a delay in obtaining required financial statements for any acquisition that we make. We have filed the registration statement of which this prospectus is a part to satisfy certain of our obligations under the registration rights agreement. The independent members of our general partner’s board of directors have made the determination to delay such requirement by 60 days.
      We will use our commercially reasonable efforts to cause the shelf registration statements to become effective under the Securities Act within 180 days of their filing and to continuously maintain the effectiveness of the shelf registration statements under the Securities Act until the first to occur of:
  •  the sale pursuant to a registration statement of all of the units covered by the shelf registration statement;
 
  •  the sale, transfer or other disposition pursuant to Rule 144 under the Securities Act of all of the units covered by the shelf registration statement;
 
  •  such time as all of the units sold in this offering and covered by a shelf registration statement and not held by affiliates of us are, in the opinion of our counsel, eligible for sale pursuant to Rule 144 without volume or manner of sale restrictions (or any successor or analogous rule) under the Securities Act;
 
  •  the units have been sold to us or any of our subsidiaries; or
 
  •  the second anniversary of the initial effective date of the shelf registration statements.
Blackout Periods
      We are permitted, under limited circumstances, to suspend the use, from time to time, of the prospectuses that are part of the shelf registration statements (and therefore suspend sales under the registration statements) for certain periods, referred to as “blackout periods,” if, among other things, any of the following occurs:
        (i) the representative of the underwriters of an underwritten offering of units by us has advised us that the sale of units under the shelf registration statements would have a material adverse effect on the offering;
 
        (ii) a majority of the members of the board of directors of our general partner, in good faith, determines that:
  •  the offer or sale of any units would materially impede, delay or interfere with any proposed financing, offer or sale of securities, acquisition, merger, tender offer, business combination,

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  corporate reorganization, consolidation or other significant transaction involving us (a “proposed transaction”);
 
  •  after receiving the advice of counsel, that the sale of the units covered by the shelf registration statements would require disclosure of non-public material information not otherwise required to be disclosed under applicable law; or
 
  •  either (1) we have a bona fide business purpose for preserving the confidentiality of a proposed transaction, (2) disclosure of such proposed transaction would have a material adverse effect on us or our ability to consummate the proposed transaction or (3) a proposed transaction renders us unable to comply with SEC requirements; or

        (iii) a majority of the members of the board of directors of our general partner, in good faith, determines that we are required by law, rule or regulation to supplement the shelf registration statements or file post-effective amendments to the shelf registration statements in order to incorporate information into the shelf registration statements, including for the purpose of:
  •  including in the shelf registration statements any prospectus required under Section 10(a)(3) of the Securities Act;
 
  •  reflecting in the prospectuses included in the shelf registration statements any facts or events arising after the effective date of the shelf registration statements (or the most recent post-effective amendments) that, individually or in the aggregate, represent a fundamental change in the information set forth in the prospectuses; or
 
  •  including in the prospectuses included in the shelf registration statements any material information with respect to the plan of distribution not disclosed in the shelf registration statements or any material change to such information.
      The cumulative blackout periods in any twelve-month period commencing on March 15, 2006 may not exceed an aggregate of 90 days and furthermore may not exceed 60 days in any 90-day period, except as a result of a review of any post-effective amendment by the SEC prior to declaring any post- effective amendment to a registration statement effective provided we have used all commercially reasonable efforts to cause such post-effective amendment to be declared effective.
      In addition to this limited ability to suspend use of the shelf registration statements, until we are eligible to incorporate by reference into the registration statements our periodic and current reports, we will be required to amend or supplement the shelf registration statements to include our quarterly and annual financial information and other developments material to us. Therefore, sales under the shelf registration statements will be suspended until the amendment or supplement, as the case may be, is filed and effective.
Initial Public Offering
      In connection with an underwritten initial public offering, the beneficiaries of the registration rights agreement will be entitled to “piggyback” registration rights and will be eligible, subject to any exclusion or limitation of selling unitholder units in such initial public offering by the managing underwriter, to include their units in the registration statement relating to such initial public offering on a pro rata basis with the Founding Investors, as described below. Upon an underwritten initial public offering by us, the beneficiaries of the registration rights agreement, whether or not they sell units in the initial public offering, will not be able to sell any units not included in our initial public offering for a period of up to 75 days following the effective date of the registration statement filed in connection with our initial public offering.
Founders Registration Rights Agreement
      The Founders Registration Rights Agreement gives the Founding Investors and their permitted transferees certain “demand” registration rights pursuant to which they will be entitled to cause us to register under the Securities Act all or a portion of their units. The Founding Investors and their permitted transferees are entitled to exercise up to three demand registration rights with respect to registrations on SEC Form S-1,

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provided that the number of units that the Founding Investors and their permitted transferees propose to include in each such registration is at least ten percent of the total number of units they held following the completion of the private equity offering. The Founding Investors and their permitted transferees also have an unlimited number of demand registration rights with respect to registrations on SEC Form S-3, provided that the gross proceeds to the selling unitholders in each such registration is expected to be at least $1 million. We will not be required to effect more than three registrations on Form S-3 pursuant to the foregoing in any calendar year. If the employment of either Cary D. Brown or Kyle A. McGraw is terminated without cause (as defined in their respective employment agreements), the terminated officer will be entitled to one “demand” registration right allowing them to register the resale of their units.
      In addition, the Founders Registration Rights Agreement provides that if we at any time intend to file on our behalf or on behalf of any of our other unitholders a registration statement in connection with a public offering of any of our securities on a form and in a manner that would permit the registration for offer and sale of our units held by the any of the Founding Investors or their permitted transferees, such groups will be able to exercise “piggyback” registration rights pursuant to which they will be entitled to participate in public offerings of our units. The Founding Investors and their permitted transferees also have piggyback registration rights with respect to any registration statement we file on behalf of any of our other unitholders in connection with a public offering of our units on a form and in a manner that would permit the registration for offer and sale of our units. However, the Founding Investors are not entitled to participate in the shelf registration statements that we file to register the resale of the units pursuant to the registration rights agreement. The piggyback registration rights will be subject to:
  •  compliance with the registration rights agreement;
 
  •  cutback rights on the part of the underwriters; and
 
  •  other conditions and limitations that may be imposed by the underwriters.
      In the event underwriters exercise their cutback rights with respect to an offering, units to be sold in the offering by us will be excluded from the registration only after all units sold in such offering as to which piggyback registration rights have been exercised have been excluded. In other words, units to be sold by us in such an offering will have a higher priority for inclusion in the offering than units which piggyback registration rights have been exercised. Furthermore, in the event the underwriters exercise their cutback rights with respect to an offering, the units held by the beneficiaries of the registration rights agreement, the Founding Investors and their respective permitted transferees will be excluded from the registration on a pro rata basis.
Other Matters
      A holder that sells our units pursuant to a shelf registration statement or as a selling unitholder in an underwritten public offering will be required to be named as a selling unitholder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such holder (including certain indemnification rights and contribution obligations). In addition, each holder of our units will be required to deliver information to be used in connection with the shelf registration statement or related prospectus related to their units in order to have such holder’s units included in the shelf registration statement.
      Each holder will be deemed to have agreed that, upon receipt of notice of the occurrence of any event that makes a statement in the prospectus which is part of the shelf registration statement relating to their units untrue in any material respect or which requires the making of any changes in such prospectus in order to make the statements therein not misleading, or of certain other events specified in the registration rights agreement, such holder will suspend the sale of our units pursuant to such prospectus until we have amended or supplemented such prospectus to correct such misstatement or omission and we have given notice that the sale of the units may be resumed.

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      We have agreed to use our commercially reasonable efforts to satisfy the criteria for listing and list or include (if we meet the criteria for listing on such exchange or market) our units on the New York Stock Exchange, American Stock Exchange or The Nasdaq National Market (as soon as practicable, including seeking to cure in our listing or inclusion application any deficiencies cited by the exchange or market), and thereafter maintain the listing on such exchange or market.
      We will bear certain expenses incident to our registration obligations upon exercise of these registration rights, including the payment of federal securities law and state blue sky registration fees, except that we will not bear any underwriting discounts or commissions or transfer taxes relating to resale of units by selling unitholders. We have agreed to indemnify each selling unitholder for certain violations of federal or state securities laws in connection with any registration statement in which such selling unitholder sells its units pursuant to these registration rights. Each selling unitholder has in turn agreed to indemnify us for federal or state securities law violations that occur in reliance upon written information it provides to us for use in the registration statement.
      We will also provide each holder of registrable units a copy of the prospectus that is a part of the registration statement relating to their units, notify such holder when such registration statement has become effective, and take certain other actions as are required to permit resales.

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MATERIAL TAX CONSEQUENCES
      This section is a discussion of the material United States federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP, counsel to us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to these matters. This section is based on current provisions of the Internal Revenue Code, existing and proposed 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 Legacy Reserves LP and our operating subsidiaries.
      This section does not address all federal income tax matters that affect us or the unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, we urge 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 our units.
      No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Andrews Kurth 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 in this discussion 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 our units and the prices at which our units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne directly by our unitholders. 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.
      For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific federal income tax issues:
  (1)  the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);
 
  (2)  whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury regulations (please read “— Disposition of Units — Allocations Between Transferors and Transferees”);
 
  (3)  whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction available to any unitholder (please read “— Tax Treatment of Operations — Depletion Deductions”);
 
  (4)  whether the deduction related to United States production activities will be available to a unitholder or the extent of such deduction to any unitholder (please read “— Tax Treatment of Operations — Deduction for United States Production Activities”); and
 
  (5)  whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).
Partnership Status
      A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner 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, even if no cash distributions are made to him. Distributions by a

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partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of his 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 in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including 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 assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 3% of our current income does not constitute qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us, and a review of the applicable legal authorities, Andrews Kurth LLP is of the opinion that more than 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can 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 subsidiaries 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 Andrews Kurth LLP. Andrews Kurth LLP is of the opinion, based upon the Internal Revenue Code, its regulations, published revenue rulings, court decisions and the representations described below, that we will be classified as a partnership, and each of our operating subsidiaries (other than the entity employing our employees) will be disregarded as an entity separate from us, for federal income tax purposes.
      In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us. The representations made by us upon which Andrews Kurth LLP has relied include:
  (a)  Neither we, nor any of our partnership or limited liability company subsidiaries, have elected nor will we elect to be treated as a corporation; and
  (b)  For each taxable year, more than 90% of our gross income has been and will be income that Andrews Kurth LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.
      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, 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 would 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 a corporation for federal income tax purposes.
      If we were taxable as a corporation 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 the 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 taxable dividend income to the extent of our current or 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 units, or taxable capital gain, after the unitholder’s tax basis in his 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 remainder of this section is based on Andrews Kurth LLP’s opinion that we are and will be classified as a partnership for federal income tax purposes.

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Unitholder Status
      Unitholders who become partners of Legacy Reserves LP will be treated as partners of Legacy Reserves LP for federal income tax purposes. Also, unitholders whose 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 units will be treated as partners of Legacy Reserves LP for federal income tax purposes.
      A beneficial owner of 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, loss, or deduction are not 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 be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to their status as partners in us for federal income tax purposes. The reference to “unitholder” in the discussion that follows are to persons who are treated as partners in Legacy Reserves LP for federal income tax purposes.
Tax Consequences of Unit Ownership
Flow-Through of Taxable Income
      We will not pay any 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 corresponding cash distributions are received by 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 share of our income, gain, loss and deduction for our taxable year or years 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 him for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of his tax basis in his units generally will be considered to be gain from the sale or exchange of those units, taxable in accordance with the rules described under “— Disposition of Units” below. To the extent that cash distributions made by us 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.”
      Any reduction in a unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “non-recourse liabilities,” will be treated as a distribution of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash, which 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 units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including recapture of intangible drilling costs, depletion and depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and 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. That income will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

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Basis of Units
      A unitholder’s initial tax basis for his units will be the amount he paid for the 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 generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, 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’s share of our nonrecourse liabilities will generally be based on his share of our profits. Please read “— Disposition of 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 his tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of its 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 amount is less than his tax basis. A unitholder 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 in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. 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 excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.
      In general, a unitholder will be at risk to the extent of his tax basis in his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by 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. Moreover, a unitholder’s at risk amount will decrease by the amount of the unitholder’s depletion deductions and will increase to the extent of the amount by which the unitholder’s percentage depletion deductions with respect to our property exceed the unitholder’s share of the basis of that property.
      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 must compute his at risk amount separately with respect to each oil or natural gas property we own, he may 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.
      The passive loss limitation generally provides that individuals, estates, trusts and some closely held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as corporate or partnership 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 limitation is applied separately with respect to each publicly traded partnership. Consequently, any losses we generate will only be available to offset our passive income generated in the future and will not be available

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to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or a unitholder’s salary or active business income. If we dispose of only part of our interest in a property, unitholders will be able to offset only their suspended passive activity losses attributable to that property against the gain on the disposition. Any remaining suspected passive activity losses will remain suspended. Notwithstanding whether a oil and natural gas property is a separate activity, 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 rules 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.
Limitation 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:
  •  interest on indebtedness properly allocable to property held for investment;
 
  •  our interest expense attributable to portfolio income; and
 
  •  the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
      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. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.
Entity-Level Collections
      If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder 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 unitholder 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 a 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 the unitholders in accordance with their percentage interests in us. If we have a net loss for an entire year, the loss will be allocated to our unitholders according to their percentage interests in us to the extent of their positive capital account balances.
      Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of the assets

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contributed to us, which assets are referred to in this discussion as “Contributed Property.” These allocations are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “book-tax disparity.” The effect of these allocations combined with our Section 754 election to a unitholder who purchases units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In the event we issue additional units or engage in certain other transactions in the future, Section 704(c) allocations will be made to all holders of partnership interests, including purchasers of units in this offering, 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 the 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 ordinary income by other 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 Section 704(c), will generally be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a unitholder’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:
  •  his relative contributions to us;
 
  •  the interests of all the unitholders in profits and losses;
 
  •  the interest of all the unitholders in cash flow; and
 
  •  the rights of all the unitholders to distributions of capital upon liquidation.
      Andrews Kurth LLP is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election,” “— Uniformity of Units” and “— Disposition of Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a unitholder’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 a partner for tax purposes 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:
  •  none of our income, gain, loss or deduction with respect to those units would be reportable by the unitholder;
 
  •  any cash distributions received by the unitholder with respect to those units would be fully taxable; and
 
  •  all of these distributions would appear to be ordinary income.
      Andrews Kurth LLP has not rendered an opinion regarding the treatment of a unitholder whose units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from 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 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 non-corporate 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 their tax advisors with respect to the impact of an investment in our units on their liability for the alternative minimum tax.
Tax Rates
      In general, the highest effective federal income tax rate for individuals currently is 35% and the maximum federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than twelve months at the time of disposition.
Section 754 Election
      We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases units directly from us, and it belongs only to the purchaser and not to other unitholders. Please also read, however, “— Allocation of Income, Gain, Loss and Deduction” above. For purposes of this discussion, a unitholder’s inside basis in our assets has two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.
      Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we will adopt), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(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 method. Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury regulations. Please read “— Tax Treatment of Operations — Uniformity of Units.”
      Although Andrews Kurth LLP is unable to opine on the validity of this approach because there is no clear 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 common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 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 a 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 “— Tax Treatment of Operations — Uniformity of Units.”
      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 depletion and depreciation

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deductions and his share of any gain 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 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 we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either 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 or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to 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 Units — Allocations Between Transferors and Transferees.”
Depletion Deductions
      Subject to the limitations on deductibility of losses discussed above, 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.
      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 products 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 daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 Bbls. This depletable amount may be allocated between oil and natural gas production, with six Mcf of domestic natural gas production regarded as equivalent to one Bbl of crude oil. The 1,000 Bbl limitation must be allocated among the independent

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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 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 indefinite.
      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 (Bbls 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 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. 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 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 crude oil deposits and also carries on substantial retailing or refining operations. An oil or natural gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order 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 Bbls of oil (or the equivalent amount of natural gas) on

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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 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 unrealized gain. Please read “— Disposition of Units — Recognition of Gain or Loss.”
Deduction for United States 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 a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentages are 3% for qualified production activities income generated in the year 2006; 6% for the years 2007, 2008, and 2009; and 9% thereafter.
      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 only taken into account if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the 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 paid by the unitholder during the calendar year and properly allocable to gross receipts from domestic production activities. 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. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders.
      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. 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 leaseholder 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.”

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      Geophysical Costs. Geophysical costs paid or incurred in connection with the exploration for, or development of, oil or gas within the United States are allowed as a deduction ratably over the 24-month period beginning on the date that such expense was 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 which are reasonable in amount.
Tax Basis, Depreciation and Amortization
      The tax basis of our assets, such as casing, tubing, tanks, pumping units and other similar property, 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 existing unitholders, and (ii) any other offering will be borne by our 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 that will result in the largest deductions being taken in the early years after assets are placed in service. 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 Units — Recognition of Gain or Loss.”
      The costs incurred 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 we may be able to amortize, and as syndication expenses, which we may not amortize. 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 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.
Disposition of Units
Recognition of Gain or Loss
      Gain or loss will be recognized on a sale of units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property he receives 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.

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      Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that 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 held for more than one year will generally be taxable as capital gain or loss. A portion of this gain or loss, which may be substantial, however, 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 “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized on 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. Net capital loss 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 gain 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. Treasury regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and those Treasury regulations.
      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:
  •  a short sale;
 
  •  an offsetting notional principal contract; or
 
  •  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 who 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 or loss 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 first business day of the month (or once traded on an exchange, as of the opening of the applicable exchange on the first business day of the month) (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

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      Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying convention, the use of this method may not be permitted under existing Treasury regulations. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between 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 unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury regulations.
      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, other than through a broker, generally is 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 person who purchases units is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may lead to the imposition of substantial penalties.
Constructive Termination
      We will be considered to have terminated for 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. 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 Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all 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.
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 amortization method and useful life applied to the common basis of that property, 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. This method is consistent with the Treasury regulations applicable to property depreciable under the accelerated cost recovery system or the modified accelerated cost recovery system, which we expect will apply to substantially all, if not all, of our depreciable property. We also intend to use this method with respect to property that we own, if any, depreciable under Section 167 of the Internal Revenue Code, even though that

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position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6). We do not expect Section 167 to apply to a material portion, if any, 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 rate as if they had purchased a direct interest in our property. If we adopt this position, it may result in lower annual 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. We will not adopt this position 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. Our counsel, Andrews Kurth LLP, is unable to opine on the validity of any of these positions. 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 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.
      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. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign 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 United States trade or business, that corporation may be subject to the United States 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 in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States 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.
      Under a ruling issued by the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent the gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he

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has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.
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 counsel 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 own 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. The partnership agreement appoints our general partner as our Tax Matters Partner.
      The Tax Matters Partner 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:
        (a) the name, address and taxpayer identification number of the beneficial owner and the nominee;
 
        (b) a statement regarding whether the beneficial owner is:
        (1) a person that is not a United States person,
 
        (2) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or
 
        (3) a tax-exempt entity;

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        (c) the amount and description of units held, acquired or transferred for the beneficial owner; and
 
        (d) 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 United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 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 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.
      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. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
        (1) for which there is, or was, “substantial authority,” or
 
        (2) as to which there is a reasonable basis and the relevant 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 could result in that kind of an “understatement” of income for which no “substantial authority” exists, we would be required to 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 to avoid liability for this penalty. More stringent rules would apply to an understatement of tax resulting from ownership of units if we were classified as a “tax shelter.” We believe we will not be classified as a tax shelter. For individuals, a substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.
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 transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. Please read “— Information Returns and Audit Procedures” above.
      Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could be subject to the following provisions of the American Jobs Creation Act of 2004:
  •  accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-related Penalties,”

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  •  for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and
 
  •  in the case of a listed transaction, an extended statute of limitations.
      We do not expect to engage in any reportable transactions.
State, Local and Other Tax Considerations
      In addition to federal income taxes, you will be subject to other taxes, including 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. We currently do business and own property in Texas, New Mexico, Oklahoma and Mississippi. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states 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 state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, 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.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.
      It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Andrews Kurth LLP has not rendered an opinion on the state local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax returns, that may be required of him.

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INVESTMENT IN LEGACY RESERVES 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 restrictions imposed by Section 4975 of the Internal Revenue Code. 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 IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:
  •  whether the investment is prudent under Section 404(a)(1)(B) of ERISA;
 
  •  whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and
 
  •  whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.
      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 are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.
      In addition to considering whether the purchase of units is a prohibited transaction, a fiduciary of an employee benefit plan 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 also would be a fiduciary of the 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.
      The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:
  •  the equity interests acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;
 
  •  the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries and certain other requirements are met; or
 
  •  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, disregarding some interests held by our general partner, its affiliates, and some other persons, is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA.
      We should qualify as an “operating company” because our business includes the acquisition and exploitation of oil and natural gas properties and therefore our underlying assets should not be considered “plan assets” under these regulations.
      Plan fiduciaries contemplating a purchase of our units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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SELLING UNITHOLDERS
      This prospectus covers units sold in our recent private equity offering. Some of the units sold in the private equity offering were sold directly to “accredited investors” as defined by Rule 501(a) under the Securities Act pursuant to an exemption from registration provided in Regulation D, Rule 506 under Section 4(2) of the Securities Act. In addition, we sold units to Friedman, Billings, Ramsey & Co., Inc. (“FBR”), who acted as initial purchaser and sole placement agent in the offering. FBR sold a portion of the units it purchased from us in transactions exempt from the registration requirements of the Securities Act to persons that it reasonably believed were “qualified institutional buyers,” as defined by Rule 144A under the Securities Act. The selling unitholders who purchased units from us or FBR in the private equity offering and their permitted transferees may from time to time offer and sell under this prospectus any or all of the units listed opposite each of their names below.
      The following table sets forth information about the number of units owned by each selling unitholder that may be offered from time to time under this prospectus. Certain selling unitholders may be deemed to be “underwriters” as defined in the Securities Act. Any profits realized by the selling unitholder may be deemed to be underwriting commissions.
      The table below has been prepared based upon the information furnished to us by the selling unitholders as of August 31, 2006. The selling unitholders identified below may have sold, transferred or otherwise disposed of some or all of their units since the date on which the information in the following table is presented in transactions exempt from or not subject to the registration requirements of the Securities Act. Information concerning the selling unitholders may change from time to time and, if necessary, we will supplement this prospectus accordingly. We cannot give an estimate as to the amount of units that will be held by the selling unitholders upon termination of this offering because the selling unitholders may offer some or all of their units under the offering contemplated by this prospectus. Each selling unitholder is registering pursuant to the registration statement, of which this prospectus is a part, 100% of the units currently held by such selling unitholder. Therefore, if each such selling unitholder sells all of the units it is offering, such selling unitholder will no longer own any of our units. The total amount of units that may be sold hereunder will not exceed the number of units offered hereby. Please read “Plan of Distribution.”
      If units are to be sold by transferees of the selling unitholders under this prospectus, we must file a post-effective amendment to the registration statement that includes this prospectus or a prospectus supplement, amending the list of selling unitholders to include the transferee as a selling unitholder. Upon being notified by a selling unitholder that it intends to use an agent or principal to sell their units, a post-effective amendment to the registration statement that includes this prospectus will be filed, naming the agent or principal as an underwriter and disclosing the compensation arrangement. All selling unitholders are subject to Rule 105 of Regulation M and are precluded from engaging in any short selling activities prior to effectiveness and for as long as they are participants in the offering.
      Except as noted below, to our knowledge, none of the selling unitholders has, or has had within the past three years, any position, office or other material relationship with us or any of our predecessors or affiliates, other than their ownership of units described below.
                 
    Number of   Percentage of
    Units That May   Units
Selling Unitholder   Be Sold   Outstanding
         
A & C Tank Sales Company, Inc.(1)
     2,941         *
A & R Agreement of Trust for Joan M. Welsh — DTD 08/31/1990 — Joan M. Welsh TTEE(2)
     1,570         *
A-Able Transmission — Corporate Investment Account(2)
     240         *
Alexandra P. Tumbleston — Personal Portfolio(2)
     2,290         *
Alexis A. Shehata — Personal Portfolio(2)
     830         *
Allied Funding Inc. 
     12,500         *
Alvin Jackson Mills Jr. 
     6,000         *

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    Number of   Percentage of
    Units That May   Units
Selling Unitholder   Be Sold   Outstanding
         
Andrea L. Kilian Trust — DTD 9/25/97 — Andrea L. Kilian TTEE(2)
     810         *
Anita L. Rankin Revocable Trust — U/ A DTD 4/28/1995 — Anita L. Rankin, TTEE(2)
     870         *
Ann C. Karter — Personal Portfolio(2)
     110         *
Ann K. Miller — Personal Portfolio(2)
     670         *
Anne Marie Romer — Personal Portfolio(2)
     1,040         *
Anthony J. Landi(3)
     300         *
Anthony J. & Patricia Landi(3)
     900         *
Anthony L. Kremer Revocable Living Trust — U/ A DTD 1/27/1998 — Anthony L. Kremer TTEE(2)
     1,770         *
Aurelia Palcher — TOD John E. Palcher(2)
     10,310         *
Baker-Hazel Funeral Home — Corporate Investment Fund(2)
     250         *
Barbara A. Muth — Revocable Living Trust U/ A DTD 10/31/96 — Barbara A. Muth, TTEE(2)
     1,560         *
Barbara McCarty — Personal Portfolio(2)
     470         *
Berol Family Trust fbo Margaret B. Beattie(4)
     11,765         *
Billy A. West — Personal Trust(2)
     3,140         *
BLT Enterprises, LLLP — Partnership(2)
     780         *
Blueprint Partners LP
     5,235         *
Blue Ridge Investments, Inc.(5)
     1,177         *
Brian L. McMurray — Personal Portfolio(2)
     1,220         *
Brian Wilmovsky
     1,000         *
Bridgette Helms IRA(6)
     556         *
Bruce Slovin
     3,637         *
Calm Waters Partnership(7)
     588,235       3.2  
Capital Ventures International(8)
     117,650         *
Carl. W. Goeckel — Personal Portfolio II(2)
     690         *
Carmine and Wendy Guerro Living Trust — U/ A DTD 7/31/2000 — C Guerro and W Guerro, TTEES(2)
     1,610         *
Carol D. Shellabarger Green — Revocable Trust DTD 4/21/00 — Carol Downing Green TTEE(2)
     1,990         *
Carrie Marie DeMange Living Trust — U/ A DTD 7/9/2004 — M. DeMange & T. DeMange, TTEES(2)
     490         *
Charles Foley
     5,000         *
Charles A. Post
     5,000         *
Charles B. Ceisel
     1,000         *
Charles L. & Miriam L. Bechtel — Joint Personal Portfolio(2)
     230         *
Charles T. Kunesh Irrevocable Trust — DTD 6/28/95 — Mary M. Kunesh, TTEE(2)
     830         *
Charles V. Simms Trust — U/ A DTD 12/28/1994 — Charles V. Simms, TTEE(2)
     1,230         *
Chris H. & Linda M. Kapolas — Joint Personal Portfolio(2)
     880         *
Cindy Ernst — Personal Portfolio(2)
     430         *
C.J. Vogel Inc. Profit Sharing Plan(9)
     1,000         *
Coleman Family Revocable Trust(10)
     2,500         *

149

Table of Contents

                 
    Number of   Percentage of
    Units That May   Units
Selling Unitholder   Be Sold   Outstanding
         
Craig & Mary Jo Sanford — Joint Personal Portfolio(2)
     550         *
CTBB Family Limited Partnership(2)
     1,280         *
Daniel W. Crotty Trust — Dated November 3, 1995 — Daniel W. Crotty, TTEE(2)
     1,730         *
Daniel W. Huthwaite & Constance R. Huthwaite
     2,940         *
Darryl W. Copeland Jr. 
     6,000         *
David L. Roer — Personal Portfolio(2)
     1,520         *
David M. Gray — Revocable Trust DTD 07-19-96 — David M. Gray, TTEE(2)
     1,990         *
David R. & Renee M. Ernst — Joint Personal Portfolio(2)
     780         *
David R. Kremer Revocable Living Trust — DTD 5/7/1996 — David R. Kremer & Ruth E. Kremer, TTEES(2)
     980         *
David Eidelman
     5,000         *
David Foley
     5,000         *
David Ross — Revocable Living Trust U/ A DTD 11/04/00 — David Ross TTEE(2)
     350         *
David Slyman Jr. — Personal Portfolio(2)
     1,290         *
Dierberg Foundation
     90,000         *
Dolores H. Russ Trust — DTD 4/20/2000 — Dolores H. Russ, TTEE(2)
     8,620         *
Don A. & Linda B. Maccubbin — Revocable Trust DTD 05/04/93 — Don A. & Linda B. Maccubbin, TTEES(2)
     2,390         *
Donald G. Tekamp Revocable Trust — DTD 8/16/2000 — Donald G. Tekamp TTEE(2)
     1,430         *
Donald Gorman — Personal Portfolio(2)
     1,070         *
Douglas & Melissa Marchal — Joint Personal Portfolio(2)
     2,540         *
Dr. Donald H. Nguyen & Lynn A. Buffington — JTWROS(2)
     340         *
Dr. Michael T. Kunesh — Revocable Trust(2)
     1,810         *
EBS Microcap Partners, L.P. — Limited Partnership(2)
     810         *
EBS Partners, LP — Limited Partnership — Primary Account(2)
     790         *
Edward White Jr. 
     1,000         *
Eileen M. Jackson — TOD(2)
     990         *
Elaine S. Berman Trust — DTD 6/30/95 — Elaine S. Berman TTEE(2)
     1,610         *
Elizabeth Ann Simms Trust — U/ A DTD 12/28/1994 — Elizabeth Ann Simms, TTEE(2)
     1,270         *
FBO Marjorie G. Kasch — U/ A/ D 3/21/80 — Thomas A. Holton TTEE(2)
     980         *
Felice M. Kantor #1 — Personal Trust U/ A DTD 06/23/93 — Felice M. Kantor TTEE(2)
     690         *
Felix R. Harke Sep IRA(11)
     750         *
First Republic Bank fbo Tarek F. Abdel-Meguid(12)
     3,000         *
Forney M. Hoke III — Personal Portfolio(2)
     920         *
Found-Mor LLC —(2)
     300         *
Francis Belmont
     1,500         *
Geddes and Company(13)
     12,000         *
George H. Welsh — Revocable Living Trust DTD 8/1/90 — Trust B — Joan M. Welsh, Co-TTEE(2)
     150         *
George Hicks — Personal Portfolio(2)
     870         *

150

Table of Contents

                 
    Number of   Percentage of
    Units That May   Units
Selling Unitholder   Be Sold   Outstanding
         
Georgetown Preparatory School, Inc.(14)
     7,353         *
Gerald E. & Deanne W. Joseph — Joint Personal Portfolio(2)
     480         *
Gerald J. Allen — Personal Portfolio(2)
     500         *
Giacomo Life Insurance — Trust DTD 4/28/01 — Jane Hughes TTEE(2)
     1,280         *
Grace G. Miller — Personal Portfolio(2)
     2,170         *
Gregory A. & Bibi A. Reber — Joint Personal Portfolio(2)
     4,620         *
Gregory Hull — Personal Portfolio(2)
     2,080         *
Gwendolyn D. Harmon — Revocable Living Trust(2)
     240         *
H. Joseph & Rosemary Wood — Joint Personal Portfolio(2)
     170         *
Hale S. Irwin
     8,800         *
Harold & Congress Hazel Trust — U/ A DTD 04/21/1991 — Congress Ann Hazel, TTEE(2)
     710         *
Harold A. & Lois M. Ferguson — Joint Personal Portfolio(2)
     710         *
Hazel B. Kidd — Personal Portfolio(2)
     350         *
Helen G. Moody — Revocable Living Trust DTD 01/17/02 — Helen G. Moody TTEE(2)
     230         *
Howard Smith — Personal Portfolio(2)
     870         *
Investors of America, LP
     60,000         *
Iroquois Master Fund Ltd.
     14,705         *
Jack R. Scherer Liv Trust — DTD 4/3/97 — Jack R. & Lana B. Scherer TTEES(2)
     150         *
Jacqueline Fowler(3)
     3,000         *
Jacqueline Slyman — Personal Portfolio(2)
     700         *
James R. Goldstein — Personal Portfolio(2)
     520         *
James and Susan Locke TBE
     14,706         *
Jan Munroe Trust — Jan Munroe TTEE(15)
     10,000         *
Janet R. Seiler Trust — DTD 5/18/2005 — Janet R. Seiler, TTEE(2)
     960         *
Jane I. Schaefer Trust(16)
     11,800         *
Janice S. Harmon Revocable Trust — Dtd 2/2/05 — Janice S. Harmon TTEE(2)
     770         *
Jean C. Marten — Personal Portfolio(2)
     1,670         *
Jeannine E. Phlipot — Personal Portfolio(2)
     1,160         *
Jeffrey M. Grieco — Revocable Living Trust DTD 7/19/2001 — Jeffrey M. Grieco, TTEE(2)
     750         *
Jennifer M. DeMange Rev. Living Trust — U/ A DTD 12/15/2001 — M. DeMange & T. DeMange, TTEES(2)
     450         *
Jerald and Francine Siegal JTWROS
     500         *
Jerome E. Muth — Revocable Living Trust U/ A DTD 10/31/96 — Jerome E. Muth, TTEE(2)
     580         *
Joan M O’Neil — Personal Portfolio(2)
     10,850         *
John & Lisa O’Neil — Joint Personal Portfolio(2)
     400         *
John A. Barron — Personal Portfolio(2)
     200         *
John A. Barron — Personal Portfolio(2)
     700         *
John B. Maynard — Personal Portfolio(2)
     3,960         *
John C. & Sarah L. Kunesh — JTWROS(2)
     37,010         *

151

Table of Contents

                 
    Number of   Percentage of
    Units That May   Units
Selling Unitholder   Be Sold   Outstanding
         
John D. Thiel
     2,059         *
John E. Meyer — Personal Portfolio(2)
     1,890         *
John J. Miller — Personal Portfolio(2)
     370         *
John T. & Julia M. Paas — JTWROS(2)
     39,830         *
Jon R. Yenor & Caroline L. Brecker — Joint Tenants(2)
     1,000         *
Jonathan H.F. Crystal(3)
     1,600         *
Jonell L. Gharst — Revocable Living Trust U/ A DTD 3/18/97 — William I. Gharst TTEE(2)
     690         *
Joseph D. Maloney — Personal Portfolio(2)
     400         *
Joyce Ann Porter — Revocable Living Trust dtd 12/1/00 — Joyce Ann Porter, TTEE(2)
     3,290         *
Kandythe J. Miller — Personal Portfolio(2)
     1,040         *
Karen A. Beach Trust — DTD 5/25/02 — Karen A. Beach, TTEE(2)
     6,350         *
Karen S. Crotty Trust DTD 06/13/1995 Karen S. Crotty, TTEE(2)
     9,070         *
Kathleen J. Lienesch Family Trust — DTD 2/2/00 — Kathleen J. Lienesch TTEE(2)
     260         *
Kathryn A. Leeper — Revocable Living Trust DTD 06-29-95 — Kathryn A. Leeper, TTEE(2)
     720         *
Kenneth E. & Doreen G. Klaus — Joint Personal Portfolio(2)
     250         *
Kevin M. Crotty Revocable Living Trust DTD 06/13/1995 Kevin M. Crotty, TTEE(2)
     3,190         *
Larry J. & Marilyn E. Lehman — JTWROS(2)
     1,020         *
Lawrence D. Sperling and Jane A. Sperling JTWROS(17)
     4,400         *
Lawrence J. Harmon Trust A — DTD 1/29/2001 — G Harmon & T Harmon & H Wall TTEES(2)
     950         *
Lawrence K. Jackson — TOD(2)
     950         *
Lawrence S. Connor — Personal Portfolio(2)
     140         *
Leo K. & Katherine H. Wingate — Joint Personal Portfolio(2)
     360         *
Lester J. & Suzan A. Charnock — JTWROS(2)
     1,470         *
Linda M. Meister — Personal Portfolio(2)
     1,280         *
Marcia M. O’Rourke — Personal Portfolio(2)
     220         *
Margaret S. Adam Revocable TRUST — DTD 4/10/02 — Margaret S. Adam, TTEE(2)
     1,810         *
Marie P. Winton Marital Trust(18)
     3,000         *
Mark Orlandini — Personal Portfolio(2)
     410         *
Martha S. Senkiw — Revocable Living Trust DTD 11/02/98 — Martha S. Senkiw, TTEE(2)
     1,130         *
Martin Hirschhorn/Vera Hirschhorn(19)
     6,000         *
Marvin E. Nevins — Personal Portfolio(2)
     2,740         *
Mary Ellen Kremer Living Trust — U/ A DTD 01/27/1998 — Mary Ellen Kremer TTEE(2)
     4,190         *
Mary J. DeMange Rev. Living Trust — U/ A DTD 12/30/1992 — M. DeMange & T. DeMange, TTEES(2)
     980         *
Mary Lou R. Baggott — Personal Portfolio(2)
     230         *
Maureen K. Aukerman — Personal Portfolio(2)
     1,110         *

152

Table of Contents

                 
    Number of   Percentage of
    Units That May   Units
Selling Unitholder   Be Sold   Outstanding
         
Melodee Ruffo — Personal Portfolio(2)
     860         *
Michael & Andrea Dakin — Personal Portfolio(2)
     220         *
Michael & Marilyn E. Lipson — JTWROS(2)
     430         *
Michael A. Houser & H. Stephen Wargo — JTWROS(2)
     790         *
Michael E. Heijer IRA R/OL
     1,250         *
Michael G. & Dara L. Bradshaw — Joint Personal Portfolio(2)
     8,240         *
Michael G. Lunsford — Personal Portfolio(2)
     680         *
Michael J. Mathile — Revocable Living Trust DTD 10/03/96(2)
     6,090         *
Michael J. Suttman — Personal Portfolio(2)
     810         *
Michael J. Wenzler — Personal Portfolio(2)
     600         *
Michael K. Stout Revocable Liv Trust — Dtd 12/27/94 — Michael K. & Carol A. Stout(2)
     1,450         *
Michael Polachek
     500         *
Milo Noble — Personal Portfolio(2)
     430         *
Monte R. Black — Personal Portfolio(2)
     5,530         *
Nadine Grelsamer
     2,500         *
Nancy L. Winton(3)
     600         *
Neal L. & Kandythe J. Miller — Joint Personal Portfolio(2)
     2,210         *
Nedda Casei-Strasbourger(3)
     300         *
Neil W. & Jeanne K. Hazel — Joint Personal Portfolio(2) Neil W. Hazel — Personal Trust(2)
     1,090 510         * *
Nosrat M. Hillman — Personal Portfolio(2)
     480         *
Pacific Partners, LP(18)
     5,900         *
Pam Graeser — Personal Portfolio(2)
     32,400         *
Pamela S. Carroll — Personal Portfolio(2)
     820         *
Patricia Landi
     300         *
Patricia Landi Trustee Revocable Trust Agreement(20)
     2,100         *
Patricia Meyer Dorn — Personal Portfolio(2)
     960         *
Patrick & Shelley McGinley(21)
     3,500         *
Patrick A. Mickley & Amy Jo Mickley — Joint Personal Portfolio(2)
     790         *
Patrick L. & Jackie L. McGohan — Joint Personal Portfolio(2)
     13,260         *
Paul & Joan Strausbaugh — Personal Portfolio(2)
     5,770         *
Paul R. & Dina E. Crnkovich — Joint Personal Portfolio(2)
     720         *
Paul S. & Cynthia J. Guthrie — Joint Personal Portfolio(2)
     560         *
Peck Family Investments, Ltd.(2)
     3,950         *
Peck Investments, LLC — Terry S. & Allan L. Peck, Managers(2)
     340         *
Peter & Noreen McInnes — Joint Personal Portfolio(2)
     840         *
Peter D. Senkiw — Revocable Living Trust DTD 11/02/98 — Peter D. Senkiw, TTEE(2)
     2,590         *
Peter I. Kenner
     29,410         *
Philip H. Wagner — Revocable Trust U/ A DTD 11/1/00 — Philip H. Wagner TTEE(2)
     1,410         *
Philip H. Wagner Trust by — Eloise P. Wagner FBO Peter S. Wagner — Dtd 12/6/93 Philip H. Wagner TTEE(2)
     1,340         *

153

Table of Contents

                 
    Number of   Percentage of
    Units That May   Units
Selling Unitholder   Be Sold   Outstanding
         
Placer Creek BMD USB II, Inc.(22)
     90,000         *
Placer Creek Partners, L.P.(23)
     93,300         *
Pleiades Investment Partners-R LP(24)
     54,223         *
Potomac Capital International Ltd.(25)
     46,788         *
Potomac Capital Partners LP(26)
     75,459         *
R&D Investment Partnership, LLP — Limited Liability Partnership(2)
     13,920         *
Rajendra Singh & Neera Singh JTWROS(27)
     29,410         *
Rajnikant Ramji Shah & Dilroza Rajnikant Shah(28)
     10,000         *
Randy H. & Pamela F. Yoakum — Joint Personal Portfolio(2)
     650         *
RAWA Limited Partnership(2)
     860         *
Raymond W. Lane — Personal Portfolio(2)
     3,320         *
Reuven M. Sacher, MD(3)
     3,000         *
Richard D. Smith — Personal Portfolio(2)
     200         *
Richard E. Holmes — Revocable Living Trust DTD 08/25/94 — Richard E. Holmes, TTEE — Sharon Longo & Marianne Nestor, Durable POA(2)
     230         *
Richard Feinberg
     10,000         *
Robert H. Smith
     7,353         *
Robert F. Mays Trust — DTD 12/7/95 — Robert F. Mays TTEE(2)
     1,030         *
Robert H. Meixner, Jr. — Personal Portfolio(2)
     220         *
Robert B. Feinberg
     15,000         *
Robert L. Kilian — Trust U/ A DTD 9/25/97 — Robert L. Kilian TTEE(2)
     640         *
Robert N. Sturwold — Personal Portfolio(2)
     400         *
Robert S. Crotty Trust DTD 02/25/1996 Robert S. Crotty, TTEE(2)
     2,460         *
Robert W. Lowry — Personal Portfolio(2)
     210         *
Roland and Fanny Anderson — JTWROS(2)
     27,910         *
Ronald E. & Sharon S. Yoakum — Joint Personal Portfolio(2)
     260         *
Ruth D. Scharf Trust — DTD 12/6/1995 — Ruth D. Scharf, TTEE(2)
     270         *
Ruth E. Kremer Revocable Living Trust — DTD 5/7/96 — David R. Kremer & Ruth E. Kremer, TTEES(2)
     3,750         *
Samuel W. Lumby — Personal Portfolio(2)
     240         *
Sandra E. Nischwitz — Personal Portfolio(2)
     1,220         *
Scott M. DeMange Rev. Living Trust — U/ A DTD 12/15/2001 — M. DeMange & T. DeMange, TTEES(2)
     570         *
Sean R. Convery — Personal Portfolio(2)
     790         *
Spindrift BMD USB II, Inc.(29)
     447,400       2.4  
Spindrift Partners, L.P.(30)
     369,300       2.0  
Stanley H. & Cynthia J. Rainey — Joint Personal Portfolio(2)
     230         *
Stephen & Cynthia Hopf — Joint Personal Portfolio(2)
     1,270         *
Steven & Victoria Conover — Joint Personal Portfolio(2)
     850         *
Steven A. Miller — Revocable Living Trust U/ A June 5, 1998 — Steven A. Miller, C.E. Liesner TTEES(2)
     280         *
Steven E. & Mary J. Ross — Joint Personal Portfolio(2)
     550         *
Steven Rand, Rothstein
     7,500         *
Steven W. & Sheryl Kaplan Papish JTWROS(3)
     500         *

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    Number of   Percentage of
    Units That May   Units
Selling Unitholder   Be Sold   Outstanding
         
Stratford Partners, LP(31)
     30,000         *
Stuckey Timberland Inc.(32)
     7,647         *
Susan J. Gagnon — Revocable Living Trust UA 8/30/95 — Susan J. Gagnon TTEE(2)
     750         *
Swank MLP Convergence Fund, LP
     117,650         *
Tanya P. Hrinyo Pavlina — Revocable Trust DTD 11/21/95 — Tanya P. Hrinyo Pavlina TTEE(2)
     260         *
The Anderson Family — Revocable Trust, DTD 09/23/02 — J. Kendall & Tamera L. Anderson, TTEES(2)
     260         *
The Charles T. Walsh Trust — DTD 12/6/2000 — Charles T. Walsh TTEE(2)
     380         *
The Christine F. Lindeman-Thomas — Revocable Living Trust DTD 08/22/91 — Christine F. Lindeman-Thomas, TTEE Gregory J. Thomas, POA(2)
     430         *
The Louis J. Thomas — Irrevocable Trust DTD 08/22/91 — Gregory J. Thomas, TTEE(2)
     750         *
Thomas A. & Nancy A. Miller — Joint Personal Portfolio(2)
     270         *
Thomas J. & Susan J. Maio — Joint Personal Portfolio(2)
     330         *
Thomas L. & Mary Leslie Falvey — Joint Personal Portfolio(2)
     7,760         *
Thomas M. DeMange Rev. Living Trust — U/ A DTD 12/30/1992 — T. DeMange & M. DeMange, TTEES(2)
     990         *
Thomas V. & Charlotte E. Moon Family Trust — Joint Personal Trust(2)
     3,680         *
Timothy J. Beach Trust — DTD 4/22/02 — Timothy J. Beach, TTEE(2)
     350         *
Timothy and Jane Matz JTWROS
     1,000         *
TNM Investments LTD — Partnership(2)
     90         *
Toby G. Weber Revocable Management Trust — DTD 6/13/2002 — Toby Guy Weber TTEE(2)
     660         *
Tonya S. Harmon — Revocable Living Trust(2)
     470         *
Tortoise Capital Resources Corporation(33)
     264,750       1.4  
Trust fbo David N. Berol uwo Kenneth R. Berol(4)
     11,765         *
Trust fbo John A. Berol uwo Kenneth R. Berol(4)
     11,765         *
United Capital Management, Inc. 
     20,000         *
Upnorth Investments, Ltd. — Trust(2)
     440         *
Vested Venture Capital
     50,000         *
Vivian D. Bichsel Revocable Living Trust — DTD 11/18/93 — Vivian D. Bichsel, TTEE(2)
     310         *
Wilbur L. & Evilina A. Brown — JTWROS — All Cap Value(2)
     1,030         *
Wilbur L. & Evilina A. Brown — JTWROS — Small Cap Value(2)
     600         *
William C. Eacho, III
     14,118         *
William J. Turner Revocable Living Trust — DTD 05/20/98 Schwab Account — William J. Turner, TTEE(2)
     580         *
William M. & Carla D. Thornton — Joint Personal Portfolio(2)
     310         *
Wrench & Associates Inc. Profit Plan(34)
     5,000         *
Yvonne A. Grieco — Revocable Living Trust DTD 7/19/01 — Yvonne A. Grieco, TTEE(2)
     360         *

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  *  Percentage of units beneficially owned does not exceed (1%).
  (1)  Joseph C. Cattaneo, the President of this unitholder, is deemed to have voting and dispositive power over the units held by this unitholder.
 
  (2)  Paul Crichton is the Director of Trading of EBS Asset Management, which is the Investment Advisor for this unitholder. By virtue of his position with EBS Asset Management, Mr. Crichton is deemed to hold investment power and voting control over the units held by this unitholder.
 
  (3)  Trainer Wortham & Co. has complete discretionary authority over the units held by this unitholder pursuant to an Investment Management Agreement.
 
  (4)  Trainer Wortham & Co. has complete discretionary authority over the units held by this unitholder pursuant to an Investment Management Agreement. A. Alexander Arnold III, Trustee, is deemed to have voting and dispositive power over the units held by this unitholder.
 
  (5)  David Henry Stevenson beneficially owns the units held by this unitholder.
 
  (6)  Bridgette Helmes beneficially owns the units held by this unitholder.
 
  (7)  Richard S. Strong, the Managing Partner of this unitholder, is deemed to have voting and dispositive power over the units held by this unitholder.
 
  (8)  Heights Capital Management, Inc., the authorized agent of this unitholder, has discretionary authority to vote and dispose of the shares held by this unitholder and may be deemed to be the beneficial owner of the units held by this unitholder. Martin Kobinger, in his capacity as Investment Manager of Heights Capital Management, Inc., may also be deemed to have investment discretion and voting power over the units held by this unitholder. Mr. Kobinger disclaims any such beneficial ownership of the units held by this unitholder.
 
  (9)  Gregory J. Vogel beneficially owns the units held by this unitholder.
(10)  Ron W. Coleman and Michelle A. Coleman as Trustees, are deemed to have voting and dispositive power over the units held by this unitholder.
 
(11)  Felix R. Harke beneficially owns the units held by this unitholder.
 
(12)  Trainer Wortham & Co. has complete discretionary authority over the units held by this unitholder pursuant to an Investment Management Agreement. Tarek F. Abdel-Meguid is affiliated with a registered broker-dealer. The units held by this unitholder were purchased in the ordinary course of business and at the time of purchase of such securities had no agreements or understandings, directly or indirectly, to distribute such units.
 
(13)  F. Michael Geddes, President of the unitholder, and C. Richard Childress, Vice President of the unitholder, are deemed to have voting and dispositive power over the units held by this unitholder.
 
(14)  Robert W. Posniewski beneficially owns the units held by this unitholder.
 
(15)  Trainer Wortham & Co. has complete discretionary authority over the units held by this unitholder pursuant to an Investment Management Agreement. Rudolph J. Schaefer III and Lauriston Castleman, Jr. are deemed to have voting and dispositive power over the units held by this unitholder.
 
(16)  David R. Harris is the Managing Director of Tocqueville Asset Management L.P., which is the Investment Advisor for this unitholder. Mr. Harris has been granted a power of attorney by this unitholder and is deemed to hold investment power and voting control over the units held by this unitholder.
 
(17)  Trainer Wortham & Co. has complete discretionary authority over the units held by this unitholder pursuant to an Investment Management Agreement. Lawrence D. Sperling is affiliated with a registered broker-dealer. The units held by this unitholder were purchased in the ordinary course of business and at the time of purchase of such securities had no agreements or understandings, directly or indirectly, to distribute such units.
 
(18)  Trainer Wortham & Co. has complete discretionary authority over the units held by this unitholder pursuant to an Investment Management Agreement. Michael B. Winton and Charles B. Winton are deemed to have voting and dispositive power over the units held by this unitholder.

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(19)  Martin Hirschhorn beneficially owns the units held by this unitholder.
 
(20)  Trainer Wortham & Co. has complete discretionary authority over the units held by this unitholder pursuant to an Investment Management Agreement. Patricia Landi is deemed to have voting and dispositive power over the units held by this unitholder. Trainer Wortham & Co. has complete discretionary authority over the units held by this unitholder pursuant to an Investment Management Agreement. A. Alexander Arnold III, Trustee, is deemed to have voting and dispositive power over the units held by this unitholder.
 
(21)  Robert Patrick McGinley beneficially owns the units held by this unitholder.
 
(22)  Wellington Management Company, LLP, as investment advisor, is deemed to have voting and dispositive power over the units held by this unitholder.
 
(23)  Wellington Management Company, LLP, as investment advisor, is deemed to have voting and dispositive power over the units held by this unitholder.
 
(24)  Paul J. Solit, Managing Member of investment advisor, is deemed to have voting and dispositive power over the units held by this unitholder.
 
(25)  Paul J. Solit, Director, is deemed to have voting and dispositive power over the units held by this unitholder.
 
(26)  Paul J. Solit, Managing Member of the General Partner, is deemed to have voting and dispositive power over the units held by this unitholder.
 
(27)  Rajendra and Neera Singh beneficially owns the units held by this unitholder.
 
(28)  Rajnikant Ramji Shah beneficially owns the units held by this unitholder.
 
(29)  Wellington Management Company, LLP, as investment advisor, is deemed to have voting and dispositive power over the units held by this unitholder.
 
(30)  Wellington Management Company, LLP, as investment advisor, is deemed to have voting and dispositive power over the units held by this unitholder.
 
(31)  Chad Comiteau and Mark Fain, the general partners of this unitholder, are deemed to have voting and dispositive power over the units held by this unitholder.
 
(32)  Wade B. Hall, President of the unitholder, is deemed to have voting and dispositive power over the units held by this unitholder.
 
(33)  Tortoise Capital Advisors, LLC (“TCA”) serves as the investment advisor to this unitholder. Pursuant to an investment advisory agreement entered into with this unitholder, TCA holds voting and dispositive power with respect to the units held by this unitholder. The investment committee of TCA is responsible for the investment management of this unitholder’s portfolio. The investment committee is comprised of H. Kevin Birzer, Zachary A. Hamel, Kenneth P. Malvey, Terry Matlack and David J. Schulte.
 
(34)  Jerry Wrench, Trustee, is deemed to have voting and dispositive power over the units held by this unitholder.

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PLAN OF DISTRIBUTION
      We are registering the units covered by this prospectus to permit selling unitholders to conduct public secondary trading of these units from time to time after the date of this prospectus. Under the registration rights agreement we entered into with selling unitholders, we agreed to, among other things, bear all expenses, other than brokers’ or underwriters’ discounts and commissions, in connection with the registration and sale of the units covered by this prospectus. We will not receive any of the proceeds of the sale of the units offered by this prospectus. The aggregate proceeds to the selling unitholders from the sale of the units will be the purchase price of the units less any discounts and commissions. A selling unitholder reserves the right to accept and, together with their agents, to reject, any proposed purchases of units to be made directly or through agents.
      The units offered by this prospectus may be sold from time to time to purchasers:
  •  directly by the selling unitholders and their successors, which includes their donees, pledgees or transferees or their successors-in-interest, or
 
  •  through underwriters, broker-dealers or agents, who may receive compensation in the form of discounts, commissions or agent’s commissions from the selling unitholders or the purchasers of the units. These discounts, concessions or commissions may be in excess of those customary in the types of transactions involved.
      Upon being notified by a selling unitholder that any material arrangement has been entered into with an underwriter, broker, dealer or agent regarding the sale of the units covered by this prospectus, a revised prospectus or prospectus supplement, if required, will be distributed which will set forth the aggregate amount and the terms of the offering, including the name or names of any underwriters, dealers or agents, any discounts, commissions and other items constituting compensation from the selling unitholders, and any discounts, commissions or concessions allowed or reallowed or paid to dealers. The prospectus supplement and, if necessary, a post-effective amendment to the registration statement of which this prospectus forms a part, will be filed with the SEC to reflect the disclosure of additional information with respect to the distribution of the units.
      The selling unitholders and any underwriters, broker-dealers or agents who participate in the sale or distribution of the units may be deemed to be “underwriters” within the meaning of the Securities Act. The selling unitholders identified as registered broker-dealers in the selling unitholders table above (under “Selling Unitholders”) are deemed to be underwriters with respect to securities sold by them pursuant to this prospectus. As a result, any profits on the sale of the units by such selling unitholders and any discounts, commissions or agent’s commissions or concessions received by any such broker-dealer or agents may be deemed to be underwriting discounts and commissions under the Securities Act. Selling unitholders who are deemed to be “underwriters” within the meaning of Section 2(11) of the Securities Act will be subject to prospectus delivery requirements of the Securities Act. Underwriters are subject to certain statutory liabilities, including, but not limited to, Sections 11, 12 and 17 of the Securities Act.
      The units may be sold in one or more transactions at:
  •  fixed prices;
 
  •  prevailing market prices at the time of sale;
 
  •  prices related to such prevailing market prices;
 
  •  varying prices determined at the time of sale; or
 
  •  negotiated prices.
      These sales may be effected in one or more transactions:
  •  on any national securities exchange or quotation on which the units may be listed or quoted at the time of the sale;

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  •  in the over-the-counter market;
 
  •  in transactions other than on such exchanges or services or in the over-the-counter market;
 
  •  through the writing of options (including the issuance by the selling unitholders of derivative securities), whether the options or such other derivative securities are listed on an options exchange or otherwise;
 
  •  through the settlement of short sales; or
 
  •  through any combination of the foregoing.
      These transactions may include block transactions or crosses. Crosses are transactions in which the same broker acts as an agent on both sides of the trade.
      In connection with the sales of the units, the selling unitholders may enter into hedging transactions with broker-dealers or other financial institutions which in turn may:
  •  engage in short sales of the units in the course of hedging their positions;
 
  •  sell the units short and deliver the units to close out short positions;
 
  •  loan or pledge the units to broker-dealers or other financial institutions that in turn may sell the units;
 
  •  enter into option or other transactions with broker-dealers or other financial institutions that require the delivery to the broker-dealer or other financial institution of the units, which the broker-dealer or other financial institution may resell under the prospectus; or
 
  •  enter into transactions in which a broker-dealer makes purchases as a principal for resale for its own account or through other types of transactions.
      To our knowledge, there are currently no plans, arrangements or understandings between any selling unitholders and any underwriter, broker-dealer or agent regarding the sale of the units by the selling unitholders. The maximum amount of compensation to be received by any participating NASD member will not exceed 8% of the total proceeds of the offering.
      We can give no assurances as to the development of liquidity or any trading market for the units.
      There can be no assurance that any selling unitholder will sell any or all of the units under this prospectus. Further, we cannot assure you that any such selling unitholder will not transfer, devise or gift the units by other means not described in this prospectus. In addition, any units covered by this prospectus that qualifies for sale under Rule 144 or Rule 144A of the Securities Act may be sold under Rule 144 or Rule 144A rather than under this prospectus. The units covered by this prospectus may also be sold to non-U.S. persons outside the U.S. in accordance with Regulation S under the Securities Act rather than under this prospectus. The units may be sold in some states only through registered or licensed brokers or dealers. In addition, in some states the units may not be sold unless it has been registered or qualified for sale or an exemption from registration or qualification is available and complied with.
      The selling unitholders and any other person participating in the sale of the units will be subject to the Exchange Act. The Exchange Act rules include, without limitation, Regulation M, which may limit the timing of purchases and sales of any of the units by the selling unitholders and any other such person. In addition, Regulation M may restrict the ability of any person engaged in the distribution of the units to engage in market-making activities with respect to the particular units being distributed. This may affect the marketability of the units and the ability of any person or entity to engage in market-making activities with respect to the units.
      We have agreed to indemnify the selling unitholders against certain liabilities, including liabilities under the Securities Act.

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      We have agreed to pay substantially all of the expenses incidental to the registration, offering and sale of the units to the public, including the payment of federal securities law and state blue sky registration fees, except that we will not bear any underwriting discounts or commissions or transfer taxes relating to the sale of the units.
VALIDITY OF THE UNITS
      The validity of the units will be passed upon for us by Andrews Kurth LLP, Houston, Texas.
EXPERTS
      The financial statements of Legacy Reserves LP, Legacy Reserves GP, LLC, Brothers Group, PITCO Properties, South Justice Properties, and Kinder Morgan Properties included in this prospectus, have been audited by BDO Seidman, LLP, an independent registered public accounting firm, to the extent and for the periods set forth in their reports appearing elsewhere herein, and are included in reliance upon such reports given upon the authority of said firm as experts in auditing and accounting.
      The financial statements of the selected interests of Paul T. Horne and the Charities Support Foundation Inc. and Affiliates, included in this prospectus, have been audited by Johnson Miller & Co., CPA’s, an independent registered public accounting firm, to the extent and for the periods set forth in their reports appearing elsewhere herein, and are included in reliance upon such reports given upon the authority of said firm as experts in auditing and accounting.
      Information included in this prospectus regarding our estimated quantities of oil and natural gas reserves was prepared by LaRoche Petroleum Consultants, Ltd., independent petroleum engineers, geologists and geophysicists, as stated in their reserve report with respect thereto. The reserve reports of LaRoche Petroleum Consultants, Ltd. for our reserves as of June 30, 2006 are attached hereto as Appendix C, in reliance upon the authority of said firm as experts with respect to the matters covered by their report and the giving of their report.
WHERE YOU CAN FIND MORE INFORMATION
      We have filed with the Securities and Exchange Commission, or the SEC, a registration statement on Form S-1 regarding the units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. This registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of the material may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website.
      We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

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INDEX TO FINANCIAL INFORMATION
         
 LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
    F-2  
    F-13  
    F-14  
    F-15  
    F-16  
    F-17  
    F-19  
 
 LEGACY RESERVES GP, LLC
    F-45  
    F-46  
    F-47  
 
 BROTHERS GROUP
    F-48  
    F-49  
    F-50  
    F-51  
    F-52  
    F-53  
 
 H2K HOLDINGS LTD. (FORMERLY KNOWN AS PAUL T. HORNE)
    F-70  
    F-71  
    F-72  
    F-73  
    F-74  
    F-75  
 
 CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
    F-86  
    F-87  
    F-88  
    F-89  
    F-90  
    F-91  
 
 PITCO PROPERTIES
    F-100  
    F-101  
    F-102  
 
 SOUTH JUSTIS PROPERTIES
    F-105  
    F-106  
    F-107  
 
 KINDER MORGAN PROPERTIES
    F-111  
    F-112  
    F-113  

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
      The following unaudited pro forma consolidated balance sheet as of September 30, 2006 and statements of operations for the year ended December 31, 2005 and the nine months ended September 30, 2006 are derived from Legacy Reserves LP’s (formerly the Moriah Group) historical consolidated financial statements, the historical combined financial statements of the Brothers Group and Selected Interests of Charities Support Foundation Inc. and Affiliates (“Foundations”), the historical financial statements of the oil and natural gas operations of Paul T. Horne (“PTH”), which have been transferred to H2K Holdings Ltd. (“H2K”) effective January 1, 2006, the historical statement of revenues and direct operating expenses of certain oil and natural gas properties acquired by MBN Properties LP from The Prospective Investment and Trading Company, Ltd and its affiliates (collectively “PITCO”), the historical statements of revenues, operating fees and operating expenses of certain oil and natural gas properties acquired by Legacy Reserves LP from Henry Holding LP (“South Justis Unit”) and the historical statements of revenues and direct operating expenses of certain oil and natural gas properties acquired by Legacy Reserves LP from Kinder Morgan (collectively “Kinder Morgan”) all included elsewhere in this prospectus, together with pro forma adjustments based on assumptions we have deemed appropriate. The unaudited pro forma consolidated statements of operations give effect to our private offering discussed below, the acquisition of the oil and natural gas properties of the Brothers Group, Foundations, H2K, PITCO, South Justis Unit, Kinder Morgan and the non-controlling interests in MBN Properties LP, and the distribution of certain assets to the owners of the Moriah Group and the Brothers Group, and this offering and the use of the proceeds therefrom as if the transactions had occurred on January 1, 2005. The acquisition from PITCO was completed as of September 14, 2005 and, accordingly, the operating results related to the acquired properties are included in Legacy’s historical results from that date. Our private offering of 5,000,000 units at an offering price of $17.00 per unit, the concurrent redemption of an aggregate 4,400,000 units from our Founding Investors for $69.9 million, the acquisition of the oil and natural gas properties of the Brothers Group, Foundations, H2K and the non-controlling interests in MBN Properties LP, and the distribution of certain assets to the owners of the Moriah Group and the Brothers Group occurred on March 15, 2006. Accordingly, the operating results of the properties acquired in this transaction are included in Legacy’s historical results from that date. The acquisition from Henry Holding LP was completed as of June 29, 2006 and the operating results related to the acquired properties are included in Legacy Reserves LP’s historical results after June 30, 2006. The acquisition from Kinder Morgan was completed on July 31, 2006 and the operating results related to the acquired properties are included in Legacy’s historical results after July 31, 2006. The transactions and the related adjustments are described in the accompanying notes. In the opinion of management, all adjustments have been made that are necessary to present in accordance with Regulation S-X the pro forma condensed consolidated financial statements. Accordingly, management has made no provision in these pro forma condensed financial statements for additional general and administrative costs it anticipates it will incur as a result of becoming a public reporting company or for reductions in general and administrative costs associated with providing services pursuant to acquired operating rights related to the South Justis Unit. Public reporting company costs are anticipated to be $2.6 million annually in excess of the costs we estimate would be incurred if we were a private company, and we estimate that our total general and administrative costs will be $422,000 higher than our pro forma 2005 and $211,000 higher than our pro forma nine months ended September 30, 2006 general and administrative costs, which include approximately $1.3 million and $0.6 million of general and administrative expenses associated with our private equity offering, respectively. General and administrative costs associated with providing services to the South Justis Unit are expected to be lower than the amounts reflected in our pro forma statements of operations for the year ended December 31, 2005 and the nine months ended September 30, 2006 by $570,000 and $213,000 respectively, as we expect to incur lower costs to provide support services to the South Justis Unit properties than the costs allocated by the seller.

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      The following unaudited pro forma consolidated statements of operations are presented for illustrative purposes only, and do not purport to be indicative of the financial position or results of operations that would actually have occurred if the transactions described had occurred as presented in such statements or that may be obtained in the future. In addition, future results may vary significantly from the results reflected in such statements due to factors described in “Risk Factors” included elsewhere in this prospectus. The following unaudited pro forma consolidated balance sheet and statement of operations should be read in conjunction with the historical financial statements referred to above and the notes thereto included elsewhere in this prospectus.

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LEGACY RESERVES LP
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31, 2005
                                                                             
                Kinder   Brothers   Charitable   H2K        
    Legacy   PITCO   South Justis   Morgan   Group   Foundations   Holdings   Pro Forma    
    Historical   Historical   Historical   Historical   Historical   Historical   Historical   Adjustments   Pro Forma
                                     
Revenues:
                                                                        
 
Oil sales
   $ 18,225,457     $ 6,433,423     $ 1,844,178     $ 6,334,583     $ 12,124,874     $ 1,251,599     $ 142,993     $ —     $ 46,357,107  
 
Gas sales
     7,317,744       3,681,679       564,450       174,939       3,783,771       595,302       49,231       —       16,167,116  
 
Realized and unrealized loss on oil and gas swaps
     (6,158,865 )     —       —       —       (4,855,124 )     —       (34,009 )     —       (11,047,998 )
                                                       
   
Total revenues
     19,384,336       10,115,102       2,408,628       6,509,522       11,053,521       1,846,901       158,215       —       51,476,225  
                                                       
Expenses:
                                                                        
 
Oil and gas production
     6,375,613       1,942,876       560,883       2,037,917       3,142,361       528,430       49,264       —       14,637,344  
 
Production and other taxes
     1,635,530       724,905       197,510       497,737       965,078       118,651       13,055       —       4,152,466  
 
General and administrative
     1,354,213       —       (822,553 )     —       1,187,145       43,001       —       495,295 (j)     3,055,597  
                                                              553,496 (j)        
                                                              245,000 (k)        
 
Dry hole costs
     —       —       —       —       204,968       —       890               205,858  
 
Depletion, depreciation and accretion
     2,291,013       —       —       —       826,800       286,913       14,536       3,165,349 (a)     18,063,342  
                                                              6,477,099 (e)        
                                                              2,038,585 (f)        
                                                              1,142,651 (l)        
                                                              1,820,396 (n)        
 
Impairment of long-lived assets
     —       —       —       —       —       5,530       —               5,530  
 
(Gain) loss on sale of assets
     20,523                               10,723               (330,740 )             (299,494 )
                                                       
   
Total expenses
     11,676,892       2,667,781       (64,160 )     2,535,654       6,337,075       982,525       (252,995 )     15,937,871       39,820,643  
                                                       
   
Operating income
     7,707,444       7,447,321       2,472,788       3,973,868       4,716,446       864,376       411,210       (15,937,871 )     11,655,582  
                                                       
Other income (expense):
                                                                        
 
Interest income
     185,308       —       —       —       844,603       —       —       (390,938 )(i)     638,973  
 
Interest expense
     (1,584,408 )     —       —       —       (396,676 )     —       —       (2,937,781 )(b)     (6,927,852 )
                                                              (148,687 )(g)        
                                                              (868,140 )(m)        
                                                              (992,160 )(o)        
 
Equity in loss of partnerships
     (495,295 )     —       —       —       (1,232,713 )     —       —       495,295 (j)     —  
                                                              679,217 (j)        
                                                              553,496 (j)        
 
Other
     45,321       —       —       —       95,601       —       —       —       140,922  
                                                       
 
Income before non-controlling interest
     5,858,370       7,447,321       2,472,788       3,973,868       4,027,261       864,376       411,210       (19,547,569 )     5,507,625  
Non-controlling interest
     538       —       —       —       —       —       —       (722,906 )(c)     —  
                                                              722,368 (h)        
                                                       
   
Net income
   $ 5,858,908     $ 7,447,321     $ 2,472,788     $ 3,973,868     $ 4,027,261     $ 864,376     $ 411,210     $ (19,548,107 )   $ 5,507,625  
                                                       
Net income per unit — basic and diluted
   $ 0.62                                                             $ 0.30  
                                                       
Shares used in computing net income per unit: basic and diluted
     9,488,921                                                       8,751,146 (d)     18,386,482  
                                                       
                                                              146,415 (l)        
                                                       
See accompanying notes to unaudited pro forma consolidated financial statements.

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LEGACY RESERVES LP
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
Nine Months Ended September 30, 2006
                                                                         
            Kinder   Brothers   Charitable            
    Legacy   South Justis   Morgan   Group   Foundations   H2K Holdings   Pro Forma    
    Historical   Historical   Historical   Historical   Historical   Historical   Adjustments   Pro Forma
                                 
Revenues:
                                                                
 
Oil sales
   $ 32,443,950     $ 1,067,065     $ 4,040,314     $ 2,614,139     $ 255,280     $ 40,640     $ —     $ 40,461,388  
 
Gas sales
     10,822,193       246,866       107,660       748,765       80,930       —       —       12,006,414  
 
Realized and unrealized loss on oil and gas swaps
     5,533,553       —       —       (1,286,784 )     —       (17,688 )     —       4,229,081  
                                                 
       
Total revenues
     48,799,696       1,313,931       4,147,974       2,076,120       336,210       22,952       —       56,696,883  
                                                 
Expenses:
                                                                
 
Oil and gas production
     10,159,887       311,809       1,237,520       696,077       111,484       13,345       —       12,530,122  
 
Production and other taxes
     2,710,392       109,948       309,227       261,143       27,002       3,302       —       3,421,014  
 
General and administrative
     3,265,163       (394,345 )     —       277,241       11,830       3,027       317,788 (j)     3,768,697  
                                                      226,743 (j)        
                                                      61,250 (k)        
 
Dry hole costs
     —       —       —       —       —       —       —       —  
 
Depletion, depreciation and accretion
     12,701,726       —       —       200,722       62,631       2,773       1,079,515 (e)     15,912,227  
                                                      407,717 (f)        
                                                      566,877 (l)        
                                                      890,266 (n)        
 
Impairment of long-lived assets
     8,572,859       —       —       —       —       —       —       8,572,859  
 
(Gain) loss on sale of assets
     —                       —               —               —  
                                                 
     
Total expenses
     37,410,027       27,412       1,546,747       1,435,183       212,947       22,447       3,550,156       44,204,919  
                                                 
     
Operating income (loss)
     11,389,669       1,286,519       2,601,227       640,937       123,263       505       (3,550,156 )     12,491,964  
                                                 
Other income (expense):
                                                                
 
Interest income
     93,659       —       —       301,380       —       —       (301,380 )(i)     93,659  
 
Interest expense
     (4,511,679 )     —       —       (207,905 )     —       —       (434,070 )(m)     (5,732,414 )
                                                      (578,760 )(o)        
 
Equity in loss of partnerships
     (317,788 )     —       —       (609,306 )     —       —       317,788 (j)     —  
                                                      382,563 (j)        
                                                      226,743 (j)        
 
Other
     14,910       —       —       6,600       —       —       —       21,510  
                                                 
   
Net income (loss)
   $ 6,668,771     $ 1,286,519     $ 2,601,227     $ 131,706     $ 123,263     $ 505     $ (3,937,272 )   $ 6,874,719  
                                                 
Net (loss) per unit -basic and diluted
   $ 0.42                                                     $ 0.37  
                                                 
Shares used in computing net (loss) per unit: basic and diluted
     15,952,509                                               2,293,039 (d)     18,391,963  
                                                 
                                                      146,415 (l)        
                                                 
See accompanying notes to unaudited pro forma consolidated financial statements.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
1. Pro Forma Adjustments
      The unaudited pro forma consolidated financial statements reflect the following adjustments:
a. In July 2005 Legacy became the primary beneficiary of MBN Properties LP. MBN Properties LP is a variable interest entity as defined by FIN 46R and is consolidated in the historical consolidated financial statements of the Moriah Group from the date of acquisition. MBN Properties LP acquired certain oil and gas assets from PITCO on September 14, 2005.
 
The purchase price allocation of the oil and gas properties acquired by MBN Properties LP on September 14, 2005 was as follows:
           
Purchase Price Consideration
        
 
Cash
   $ 66,151,723  
 
Acquisition Costs
     496,473  
 
Purchase price adjustment
     (2,774,088 )
       
Total purchase consideration
   $ 63,874,108  
       
Purchase Price Allocation
        
 
Oil and Gas Properties
   $ 64,319,277  
 
Asset retirement obligation
     (445,169 )
       
    $ 63,874,108  
       
As a result of the purchase above, record incremental depreciation, depletion, amortization and accretion, using the units of production method.
 
b. To record interest expense associated with debt of approximately $67.5 million incurred to fund the acquisition of oil and gas properties by MBN Properties LP on September 14, 2005 using the weighted average interest rate of MBN Properties LP of 6.02%.
 
c. To record the non-controlling interest share of the MBN Properties LP income (loss) related to the PITCO properties.
 
d. To reflect the units issued in the Legacy Formation.
 
On March 15, 2006, Legacy completed a private equity offering in which it issued 5,000,000 limited partnership units at a gross price of $17.00 per unit, netting $78.7 million after initial purchaser’s discount, placement agent’s fees and expenses. Simultaneous with the completion of this offering, Legacy purchased the oil and natural gas properties of the Brothers Group, H2K Holdings Ltd. and the Charitable Support Foundations, Inc. and its affiliates. Legacy also purchased the oil and natural gas properties owned by MBN Properties, LP. In the case of the Brothers Group and H2K Holdings Ltd. those entities exchanged their oil and natural gas properties for limited partnership units. The owners of the Moriah Group, the Brothers Group and H2K Holdings Ltd. (the “Founding Investors”) exchanged 4.4 million of their units for $69.9 million in cash. The Moriah Group has been treated as the acquiring entity in the Legacy Formation. With the exception of its assumption of liabilities associated with the oil and natural gas swaps it acquired, the other depreciable assets of the Brothers Group (office furniture and equipment and vehicles) and certain unamortized deferred financing costs of the Moriah Group, Legacy did not acquire any other assets or liabilities of the Moriah Group, the Brothers Group, H2K Holdings Ltd. or the Charitable Support Foundations, Inc. and its affiliates. The removal of these assets and liabilities of the Moriah Group was reflected as a deemed dividend in Legacy’s September 30, 2006 statement of unitholders’ equity.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
     The following table sets forth the units issued in the Legacy Formation transaction:
           
    Number of Units
     
Moriah Properties Ltd.
     7,334,070  
DAB Resources, Ltd. 
     859,703  
       
 
Moriah Group
     8,193,773  
Brothers Group
     6,200,357  
H2K Holdings Ltd. 
     83,499  
MBN Properties LP
     3,162,438  
Legacy units
     600,000  
       
 
Total units issued at Legacy Formation
     18,240,067  
       
  In addition to the 18,240,067 units issued at Legacy Formation, 52,616 restricted management units were issued to employees of Legacy concurrent with, but not as a part of, the Legacy Formation.
e. On March 15, 2006, Legacy Reserves LP, as part of its formation transactions, purchased oil and natural gas properties from the Brothers Group, H2K Holdings Ltd. and three charitable foundations, which included the assumption of liabilities associated with oil and natural gas swaps. The following table sets forth the purchase price allocation of this transaction:
                   
    Number of Units   Purchase Price of
    at $17.00 per unit   Assets Acquired
         
Brothers Group
     6,200,357     $ 105,406,069  
H2K Holdings Ltd. 
     83,499       1,419,483  
Cash paid to three charitable foundations
     —       7,682,854  
             
 
Total purchase price before liabilities assumed
             114,508,406  
Plus:
                
 
Oil and natural gas swap liabilities assumed
             3,147,152  
 
Asset retirement obligations incurred
             1,467,241  
Less:
                
 
Office furniture, equipment and vehicles acquired
             (107,275 )
             
Total purchase price allocated to oil and natural gas properties acquired
           $ 119,015,524  
             
  As a result of the purchase above, record incremental depreciation, depletion, amortization and accretion, using the units of production method.
f. On March 15, 2006, in addition to the 3,162,438 common units issued to MBN Properties LP as part of the Legacy Formation transaction, Legacy paid $65.3 million in cash to MBN Properties LP to acquire that portion of the oil and natural gas properties of MBN Properties LP it did not already own by virtue of the Moriah Group’s ownership of a 46.22% limited partnership interest in MBN Properties LP. In addition, Legacy paid $1,980,468 to MBN Management LLC to reimburse expenses incurred by that

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
entity in anticipation of the Legacy Formation. The following table sets forth the calculation of the step-up of oil and natural gas property basis with respect to this interest acquired:
                   
    Number of Units   Purchase Price of
    at $17.00 per unit   Assets Acquired
         
Units issued to MBN Properties LP
     3,162,438     $ 53,761,446  
Cash paid to MBN Properties LP
     —       65,300,000  
             
 
Total purchase price before liabilities assumed
             119,061,446  
Plus:
                
 
Oil and natural gas swap liabilities assumed
             2,539,625  
 
ARO liabilities assumed
             453,913  
Less:
                
 
Net book value of other property and equipment on MBN Properties LP at March 14, 2006
             (39,056 )
             
              122,015,928  
Less:
                
 
Net book value of oil and gas assets on MBN Properties LP at March 14, 2006
             (62,990,390 )
             
Purchase price in excess of net book value of assets
             59,025,538  
Less:
                
 
Share already owned by Moriah via consolidation of MBN Properties LP
     46.22 %     (27,281,604 )
             
Non-controlling interest share to record(a)
             31,743,934  
Plus:
                
 
Elimination of deferred financing costs related to non-controlling interests’ share of MBN Properties LP
             164,202  
 
Reimbursement of Brothers Group’s share of MBN Management LLC losses from inception through March 14, 2006
             780,239  
             
MBN Properties LP purchase price to allocate to oil and natural gas properties
           $ 32,688,375  
             
Units related to purchase of non-controlling interest(a)
     1,867,290          
Units related to interest previously owned by Moriah Group
     1,295,148          
             
 
Total units issued to MBN Properties LP
     3,162,438          
             
      As a result of the purchase above, record incremental depreciation, depletion, amortization and accretion, using the units of production method.
g. To record incremental interest expense associated with refinancing of $65.8 million incurred to fund the acquisition of oil and gas properties of Brothers, Foundations and H2K, using an interest rate of 6.5% to reflect the interest rate structure of the new credit facility executed at the time the private equity offering closed (as compared with the original $67.5 million borrowed to acquire the PITCO properties at 6.02% — see b. above).

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
h. To eliminate the non-controlling interest share of the MBN Properties LP income (loss) related to the PITCO properties.
 
i. To eliminate interest income on notes receivable not acquired.
 
j. The Moriah Group and the Brothers Group also owned an interest in MBN Management LLC, whose purpose was to manage the oil and gas properties of MBN Properties LP and fund certain expenses and they accounted for their interests under the equity method of accounting. These interests were not acquired. The effect on the unaudited pro forma consolidated statements of operations is to reclassify the equity in loss of MBN Management LLC to general and administrative expense. In addition, the Brothers Group accounted for its investment in MBN Properties LP under the equity method, and an adjustment has been made to eliminate the equity method loss since the operations of MBN Properties LP are now wholly-owned. The adjustments are as follows:
                     
        Nine Months
    Year Ended   Ended
    December 31, 2005   September 30, 2006
         
Moriah Group — MBN Management LLC
   $ 495,295     $ 317,788  
             
Brothers Group:
                
 
MBN Properties LP
   $ 679,217     $ 382,563  
 
MBN Management LLC
     553,496       226,743  
             
   
Total Brothers Group
   $ 1,232,713     $ 609,306  
             
k. Record additional compensation expense resulting from Employment Agreements executed at the closing of the private equity offering.
 
l. On June 29, 2006, Legacy purchased oil and natural gas properties from Henry Holding LP in eastern New Mexico in the South Justis Unit (“SJU”) and the right to operate these properties. The stated purchase price was $14 million cash plus the issuance of 138,000 units on June 29, 2006 and 8,415 units on November 10, 2006 at $17.00 per unit ($2,346,000 and $143,055, respectively) less final adjustments of approximately $624,000. The effective date of our ownership is May 1, 2006. Legacy has been elected operator of the SJU following the closing of the transaction, which entitles Legacy to a contractual overhead reimbursement of approximately $127,500 per month from its partners in the SJU. The estimated $15.8 million net purchase price was allocated (not including the $143,055 relating to the 8,415 units issued on November 10, 2006) with $2.9 million recorded as lease and well equipment, $5.9 million of leasehold costs and $7.0 million capitalized as an intangible asset relating to the operating rights associated with the SJU. The lease and well equipment and leasehold costs will be depleted using the units of production method. The capitalized operating rights associated with the SJU will be amortized over the estimated total well months the wells in the SJU are expected to be operated. $137,453 of asset retirement obligations were recorded in connection with this transaction.
 
As a result of the purchase above, record incremental depreciation, depletion, amortization and accretion.
 
m. To record incremental interest expense associated with the $12.6 million of borrowings under Legacy’s revolving credit agreement incurred to fund the acquisition of SJU oil and natural gas properties from Henry Holding LP, using an interest rate of 6.89% to reflect the interest rate at closing of the acquisition on June 29, 2006.
 
n. On July 31, 2006 Legacy purchased oil and natural gas properties from Kinder Morgan located in the Permian Basin The stated purchase price was $18 million cash before post-closing adjustments which have not been finally determined. The effective date of our ownership is July 1, 2006. The estimated

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$17.3 million net purchase price was allocated with $4.6 million recorded as lease and well equipment and $12.7 million of leasehold costs. Legacy had paid a $2.0 million cash deposit to Kinder Morgan on June 30, 2006 which is recorded on Legacy’s consolidated balance sheet as proved property. Asset retirement obligations of $1,383,180 were recorded in connection with this transaction.
 
As a result of the purchase above, record incremental depreciation, depletion, amortization and accretion, using the units of production method.
 
o. To record incremental interest expense associated with $14.4 million of borrowings under Legacy’s revolving credit agreement incurred to fund the acquisition of oil and natural gas properties from Kinder Morgan, using an interest rate of 6.89% to reflect the interest rate at closing of the acquisition on July 31, 2006.
2.         Oil and Natural Gas Reserve Disclosures
      The following table sets forth certain unaudited pro forma information concerning our proved oil and natural gas reserves for the year ended December 31, 2005, giving effect to the acquisition of oil and natural gas properties from the Brothers Group, Foundations, H2K, MBN/PITCO, South Justis, and Kinder Morgan as if the transactions had occurred on January 1, 2005. There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represent estimates only and should not be construed as being exact:
                                                                     
    Oil (MBbls)    
         
    Legacy/   MBN/   South   Kinder   Brothers       Pro Forma
    Moriah   PITCO   Justis   Morgan   Group   Foundations   H2K   Total
                                 
Total Proved Reserves:
                                                                
 
Balance, December 31, 2004
     4,109       2,558       391       995       3,239       372       40       11,704  
   
Purchases of minerals-in-place
     29       —       —       —       6       —       —       35  
   
Extensions and discoveries
     —       98       —       —       —       —       —       98  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     794       711       180       —       512       87       9       2,293  
   
Revisions of previous estimates due to prices and performance
     237       62       1       353       165       25       3       846  
   
Production
     (293 )     (187 )     (34 )     (117 )     (237 )     (27 )     (3 )     (898 )
                                                 
 
Balance, December 31, 2005
     4,876       3,242       538       1,231       3,685       457       49       14,078  
                                                 
Proved Developed Reserves:
                                                                
 
December 31, 2004
     4,109       2,256       391       995       3,239       372       40       11,402  
 
December 31, 2005
     4,143       2,237       464       1,231       3,213       377       41       11,706  

F-10

Table of Contents

LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                                                                     
    Natural Gas (MMcf)    
         
    Legacy/   MBN/   South   Kinder   Brothers       Pro Forma
    Moriah   PITCO   Justis   Morgan   Group   Foundations   H2K   Total
                                 
Total Proved Reserves:
                                                                
 
Balance, December 31, 2004
     10,470       8,810       751       396       7,372       1,066       112       28,977  
   
Purchases of minerals-in-place
     28       —       —       —       35       —       —       63  
   
Extensions and discoveries
     —       146       —       —       —       —       —       146  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     1,258       3,260       368       —       853       115       14       5,868  
   
Revisions of previous estimates due to prices and performance
     490       1,633       31       196       311       82       6       2,749  
   
Production
     (766 )     (872 )     (71 )     (47 )     (558 )     (78 )     (8 )     (2,400 )
                                                 
 
Balance, December 31, 2005
     11,480       12,977       1,079       545       8,013       1,185       124       35,403  
                                                 
Proved Developed Reserves:
                                                                
 
December 31, 2004
     10,470       8,810       751       396       7,372       1,066       112       28,977  
 
December 31, 2005
     10,498       10,120       953       545       7,346       1,076       113       30,651  
      Summarized in the following tables is information for our standardized measure of discounted cash flows relating to proved reserves as of December 31, 2005, giving effect to the acquisition of oil and natural gas properties from the Brothers Group, Foundations H2K, MBN/PITCO, South Justis, and Kinder Morgan as if the transactions had occurred on January 1, 2005. Future cash flows are computed by applying year-end pricing relating to our proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. The information should be viewed only as a form of standardized disclosure concerning possible future cash flows that would result under the assumptions used, but should not be viewed as indicative of fair market value. Reference is made to the Founders Group historical financial statements for the fiscal year ended December 31, 2005, and the Statements of Revenues and Direct Operating Expenses of certain oil and natural gas properties acquired from PITCO, South Justis, and Kinder Morgan included herein, for a discussion of the assumptions used in preparing the information presented.
                                                                   
    December 31, 2005
     
    Legacy/   MBN/   South   Kinder   Brothers       Pro Forma
    Moriah   PITCO   Justis   Morgan   Group   Foundations   H2K   Total
                                 
    (Thousands)
Future cash flows
   $ 376,697     $ 307,324     $ 41,748     $ 74,618     $ 279,102     $ 36,354     $ 3,886     $ 1,119,729  
Future costs:
                                                                
 
Production
     (145,486 )     (97,310 )     (18,323 )     (38,082 )     (109,461 )     (14,182 )     (1,505 )     (424,349 )
 
Development
     (13,127 )     (14,482 )     (2,798 )     —       (8,606 )     (1,442 )     (145 )     (40,600 )
                                                 
Future net cash flows before income taxes
     218,084       195,532       20,627       36,536       161,035       20,730       2,236       654,780  
10% annual discount for estimated timing of cash flows
     (119,157 )     (102,462 )     (9,639 )     (16,906 )     (86,188 )     (11,392 )     (1,230 )     (346,974 )
                                                 
Standardized measure of discounted net cash flows
   $ 98,927     $ 93,070     $ 10,988     $ 19,630     $ 74,847     $ 9,338     $ 1,006     $ 307,806  
                                                 

F-11

Table of Contents

LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The following table sets forth the principal sources of change in discounted future net cash flows (dollars in thousands):
                                                                     
    Year Ended December 31, 2005    
         
    Legacy/   MBN/   South   Kinder   Brothers       Pro Forma
    Moriah   PITCO   Justis   Morgan   Group   Foundations   H2K   Total
                                 
    (Thousands)    
Increase (decrease):
                                                                
 
Sales, net of production costs
   $ (13,606 )   $ (11,373 )   $ (1,650 )   $ (3,974 )   $ (11,801 )   $ (1,200 )   $ (130 )   $ (43,734 )
 
Net change in sales prices, net of production costs
     31,307       27,338       3,730       5,335       23,631       2,435       325       94,101  
 
Changes in estimated future development costs
     (10,175 )     (13,080 )     —       —       (6,434 )     (1,117 )     (109 )     (30,915 )
 
Extensions and discoveries, net of future production and development costs
     —       2,789       —       —       —       —       —       2,789  
 
Previously estimated development costs incurred
     (178 )     —       —       —       (120 )     (20 )     (2 )     (320 )
 
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     18,877       26,725       3,713       —       12,630       2,057       207       64,209  
 
Revisions of previous estimates due to prices and performance
     4,929       6,279       104       5,718       3,409       595       106       21,140  
 
Purchase of minerals-in-place
     477       —       —       —       231       —       —       708  
 
Other
     1,984       4,412       (780 )     1,211       2,303       577       (41 )     9,666  
 
Accretion of discount
     4,955       3,749       381       898       3,874       457       50       14,364  
                                                 
 
Net increase
     38,570       46,839       5,498       9,188       27,723       3,784       406       132,008  
 
Standardized measure of discounted net cash flows:
                                                                
   
Beginning of year
     60,357       46,231       5,490       10,442       47,124       5,554       600       175,798  
                                                 
   
End of year
   $ 98,927     $ 93,070     $ 10,988     $ 19,630     $ 74,847     $ 9,338     $ 1,006     $ 307,806  
                                                 

F-12

Table of Contents

Report of Independent Registered Public Accounting Firm
Legacy Reserves LP
Midland, Texas
      We have audited the accompanying consolidated balance sheets of Legacy Reserves LP (formerly the Moriah Group), as defined in Note 1 (a), as of December 31, 2004 and 2005 and the related consolidated statements of operations, unitholders’ equity, and cash flows for each of the years in the three year period ended December 31, 2005. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’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 Legacy Reserves LP at December 31, 2004 and 2005 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
      As discussed in Note 13 to the consolidated financial statements, effective January 1, 2003, the Partnership changed its method of accounting for asset retirement obligations.
  /s/ BDO SEIDMAN, LLP
Houston, Texas
May 5, 2006

F-13

Table of Contents

LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
CONSOLIDATED BALANCE SHEETS
                             
    December 31,    
        September 30,
    2004   2005   2006
             
            (Unaudited)
ASSETS
                        
Current assets:
                        
 
Cash and cash equivalents
   $ 768,763     $ 1,954,923     $ 1,644,227  
 
Accounts receivable, net:
                        
   
Oil and natural gas
     2,639,640       6,051,802       8,106,338  
   
Joint interest owners
     718,909       113,837       2,363,142  
   
Affiliated entities and other (Notes 5 and 7)
     12,521       103,850       13,732  
 
Notes receivable — affiliated entities (Note 3)
     2,380,000       —       —  
 
Fair value of oil and natural gas swaps (Note 10)
     —       46,675       3,702,217  
 
Prepaid expenses and other current assets
     48,250       —       227,666  
                   
   
Total current assets
     6,568,083       8,271,087       16,057,322  
                   
Oil and natural gas properties, at cost:
                        
Proved oil and natural gas properties, at cost, using the successful efforts method of accounting: (Note 15)
     18,270,228       85,363,482       278,113,588  
Unproved properties
     —       2,928       72,428  
Accumulated depletion, depreciation and amortization
     (6,046,262 )     (8,194,385 )     (29,136,979 )
                   
      12,223,966       77,172,025       249,049,037  
                   
Other property and equipment, net
     —       4,198       281,876  
Subordinated notes receivable (Note 6)
     —       304,312       —  
Operating rights (Note 1(k))
     —       —       6,869,671  
Other assets, net
     —       1,190,569       584,246  
                   
    $ 18,792,049     $ 86,942,191     $ 272,842,152  
                   
 
LIABILITIES AND UNITHOLDERS’ EQUITY
                        
Current liabilities:
                        
 
Current portion of notes payable (Note 4)
   $ 2,000,000     $ —     $ —  
 
Accounts payable
     56,224       451,652       924,822  
 
Accrued oil and natural gas liabilities
     2,067,731       3,174,752       5,473,826  
 
Due to affiliates (Note 6)
     —       194,907       187,503  
 
Fair value of oil and natural gas swaps (Note 10)
     679,789       199,624       —  
 
Asset retirement obligation (Note 13)
     80,482       175,944       319,446  
 
Other
     13,200       365,326       1,763,674  
                   
   
Total current liabilities
     4,897,426       4,562,205       8,669,271  
Long-term debt (Note 4)
     —       52,473,000       106,800,000  
Fair value of oil and natural gas swaps (Note 10)
     —       3,155,054       2,441,755  
Asset retirement obligation (Note 13)
     1,872,384       2,126,203       5,373,193  
Subordinated notes payable — partners (Note 6)
     —       14,716,791       —  
                   
Total liabilities
     6,769,810       77,033,253       123,284,219  
                   
Commitments and contingencies (Note 8)
                        
Unitholders’ equity:
                        
 
Limited partners’ equity — 9,488,921, 9,488,921 and 18,386,817 units issued and outstanding at December 31, 2004 and 2005 and September 30, 2006, respectively
     12,010,217       9,899,029       149,411,178  
 
General partner’s equity (0.1%)
     12,022       9,909       146,755  
                   
Total unitholders’ equity
     12,022,239       9,908,938       149,557,933  
                   
    $ 18,792,049     $ 86,942,191     $ 272,842,152  
                   
See accompanying notes to consolidated financial statements.

F-14

Table of Contents

LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
CONSOLIDATED STATEMENTS OF OPERATIONS
                                             
        Nine Months Ended
    Year Ended December 31,   September 30,
         
    2003   2004   2005   2005   2006
                     
                (Unaudited)
Revenues:
                                        
 
Oil sales
   $ 7,918,802     $ 10,997,515     $ 18,225,457       11,419,348       32,443,950  
 
Natural gas sales
     3,696,957       3,945,400       7,317,744       3,871,967       10,822,193  
 
Realized and unrealized gain (loss) on oil and natural gas swaps (Note 10)
     (282,872 )     (632,783 )     (6,158,865 )     (7,649,444 )     5,533,553  
                               
   
Total revenues
     11,332,887       14,310,132       19,384,336       7,641,871       48,799,696  
                               
Expenses:
                                        
 
Oil and natural gas production
     3,495,573       4,345,249       6,375,613       3,610,209       10,159,887  
 
Production and other taxes
     661,563       927,657       1,635,530       1,140,465       2,710,392  
 
General and administrative
     543,221       731,200       1,354,213       438,881       3,265,163  
 
Dry hole costs
     1,464,607       822       —       —       —  
 
Depletion, depreciation, amortization and accretion
     765,620       883,457       2,291,013       735,518       12,701,726  
 
Impairment of long-lived assets
     471,394       —       —       —       8,572,859  
 
Loss on sale of assets
     —       —       20,523       —       —  
                               
   
Total expenses
     7,401,978       6,888,385       11,676,892       5,925,073       37,410,027  
                               
   
Operating income (loss)
     3,930,909       7,421,747       7,707,444       1,716,798       11,389,669  
Other income (expense):
                                        
 
Interest income
     56,390       419,257       185,308       153,423       93,659  
 
Interest expense (Note 4)
     (94,284 )     (213,711 )     (1,584,408 )     (292,689 )     (4,511,679 )
 
Gain on sale of partnership investment
     —       1,292,169       —       —       —  
 
Equity in income (loss) of partnerships (Note 6)
     311,367       183,474       (495,295 )     (337,949 )     (317,788 )
 
Other
     2,554       91,483       45,321       44,971       14,910  
                               
 
Income (loss) before non-controlling interest
     4,206,936       9,194,419       5,858,370       1,284,554       6,668,771  
 
Non-controlling interest
     —       —       538       538       —  
                               
   
Income (loss) from continuing operations
     4,206,936       9,194,419       5,858,908       1,285,092       6,668,771  
 
Discontinued operations (Note 11)
                                        
   
Income (loss) from operations
     10,234       14,981       —       —       —  
   
Gain on disposal
     233,073       7,165       —       —       —  
                               
   
Income from discontinued operations
     243,307       22,146       —       —       —  
 
Cumulative effect of accounting change
     (223,377 )     —       —       —       —  
                               
   
Net income (loss)
   $ 4,226,866     $ 9,216,565     $ 5,858,908     $ 1,285,092     $ 6,668,771  
                               
Earnings per unit — Basic and diluted:
                                        
 
Income (loss) from continuing operations
   $ 0.44     $ 0.97     $ 0.62     $ 0.14     $ 0.42  
                               
 
Income (loss) from discontinued operations
   $ 0.03     $ —     $ —     $ —     $ —  
                               
 
Cumulative effect of accounting change
   $ (0.02 )     —       —       —       —  
                               
 
Net Income (loss)
   $ 0.45     $ 0.97     $ 0.62     $ 0.14     $ 0.42  
                               
Units used in computing earnings per unit:
                                        
 
Basic and diluted
     9,488,921       9,488,921       9,488,921       9,488,921       15,952,509  
                               
See accompanying notes to consolidated financial statements.

F-15

Table of Contents

LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
CONSOLIDATED STATEMENT OF UNITHOLDERS’ EQUITY
                                 
    Number of           Total
    Common   General   Limited   Partners’
    Units   Partner   Partner   Capital
                 
Balance, January 1, 2003
     9,488,921     $ 6,847     $ 6,841,933     $ 6,848,780  
Capital contributions
     —       325       324,366       324,691  
Distributions to partners
     —       (3,303 )     (3,299,219 )     (3,302,522 )
Distributions of oil and natural gas properties to partners
     —       (819 )     (818,652 )     (819,471 )
Net income
     —       4,227       4,222,639       4,226,866  
                         
Balance, December 31, 2003
     9,488,921       7,277       7,271,067       7,278,344  
Capital contributions
     —       60       59,467       59,527  
Distributions to partners
     —       (4,532 )     (4,527,665 )     (4,532,197 )
Net income
     —       9,217       9,207,348       9,216,565  
                         
Balance, December 31, 2004
     9,488,921       12,022       12,010,217       12,022,239  
Capital contributions
     —       144       143,546       143,690  
Deemed capital contribution
     —       155       154,994       155,149  
Distributions to partners
     —       (8,271 )     (8,262,777 )     (8,271,048 )
Net income
     —       5,859       5,853,049       5,858,908  
                         
Balance, December 31, 2005
     9,488,921     $ 9,909     $ 9,899,029     $ 9,908,938  
Capital contributions
     —       19       19,337       19,356  
Distributions to owners
     —       (2,297 )     (2,294,617 )     (2,296,914 )
Deemed dividend to Moriah Group owners
     —       (3,878 )     (3,874,337 )     (3,878,215 )
Net proceeds from private equity offering
     5,000,000       77,895       77,816,759       77,894,654  
Redemption of Founding Investors’ units
     (4,400,000 )     (69,938 )     (69,868,062 )     (69,938,000 )
Units issued to MBN Properties LP in exchange for the non-controlling interests’ share of oil and natural gas properties
     1,867,290       31,744       31,712,190       31,743,934  
Units issued to the Brothers Group in exchange for oil and natural gas properties
     6,200,357       105,406       105,300,663       105,406,069  
Units issued to H2K Holdings Ltd. in exchange for oil and natural gas properties and other assets
     83,499       1,419       1,418,064       1,419,483  
Dividend — reimbursement of offering costs paid by MBN Management LLC
     —       (1,200 )     (1,199,029 )     (1,200,229 )
Units issued to Henry Holding LP in exchange for oil and natural gas properties
     138,000       —       2,346,000       2,346,000  
Units issued to Legacy Board of Directors
     8,750       —       148,750       148,750  
Compensation expense on restricted unit awards issued to employees
     —       —       191,959       191,959  
Compensation expense on unit options awards issued to employees
     —       —       116,850       116,850  
Distributions to unitholders
     —       (8,993 )     (8,984,480 )     (8,993,473 )
Net income
     —       6,669       6,662,102       6,668,771  
                         
Balance, September 30, 2006 (unaudited)
     18,386,817     $ 146,755     $ 149,411,178     $ 149,557,933  
                         
See accompanying notes to consolidated financial statements.

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LEGACY RESERVES (FORMERLY MORIAH GROUP)
CONSOLIDATED STATEMENTS OF CASH FLOWS
                                             
        Nine Months Ended
    Year Ended December 31,   September 30,
         
    2003   2004   2005   2005   2006
                     
                (Unaudited)
Cash flows from operating activities:
                                        
 
Net income (loss)
   $ 4,226,866     $ 9,216,565     $ 5,858,908     $ 1,285,092     $ 6,668,771  
 
Adjustment to reconcile net income to net cash provided by operating activities:
                                        
 
Dry hole costs
     1,464,607       822       —       —       —  
 
Depletion, depreciation, amortization and accretion
     768,591       883,457       2,291,013       735,518       12,701,726  
 
Impairment of long-lived assets
     471,394       —       —       —       8,572,859  
 
Amortization of financing costs
     —       —       93,776       —       318,344  
 
(Gain) loss on oil and natural gas swaps
     (340,179 )     558,953       6,158,865       7,649,444       (5,533,553 )
 
Unit-based compensation
     —       —       —       —       457,559  
 
(Gain) loss on sale of assets
     (233,073 )     (1,299,334 )     20,523       —       —  
 
Equity in (income) loss of partnerships
     (311,367 )     (183,474 )     495,295       337,949       317,788  
 
Accrued interest on subordinated notes payable — partners
     —       —       817,757       90,846       —  
 
Accrued interest on subordinated notes receivable — partners
     (48,624 )     —       (24,797 )     (8,900 )     —  
 
Distributions from oil and gas partnership
     138,600       103,950       —       —       —  
 
Non-controlling interest
     —       —       (538 )     (538 )     —  
 
Non-cash effect of accounting change
     223,377       —       —       —       —  
 
Changes in assets and liabilities:
                                        
   
Increase in accounts receivable, oil and natural gas
     (228,692 )     (762,905 )     (3,412,162 )     (2,098,019 )     (6,302,693 )
   
(Increase) decrease in accounts receivable, joint interest owners
     (223,176 )     505,826       605,072       534,478       (2,498,932 )
   
Increase in accounts receivable, other
     —       (30,270 )     (91,329 )     (8,042 )     (449,850 )
   
(Increase) decrease in other assets
     19,792       7,636       (87,887 )     1,839       (702,386 )
   
Increase (decrease) in accounts payable
     66,035       (267,960 )     395,428       337,240       687,111  
   
Increase (decrease) in accrued oil and natural gas liabilities
     804,860       (147,197 )     1,107,021       192,141       3,819,783  
   
Increase in due to affiliates
     —       —       194,907       1,050,428       1,246,811  
   
Increase (decrease) in other liabilities
     113       —       (13,200 )     24,248       2,514,897  
                               
   
Total adjustments
     2,572,258       (630,496 )     8,549,744       8,838,632       15,149,464  
                               
   
Net cash provided by operating activities
     6,799,124       8,586,069       14,408,652       10,123,724       21,818,235  
                               
Cash flows from investing activities:
                                        
 
Investment in oil and natural gas properties
     (4,046,672 )     (3,325,151 )     (66,910,315 )     (65,497,889 )     (45,353,007 )
 
Investment in other equipment
     —       —       (4,198 )     —       (200,124 )
 
Investment in operating rights
     —       —       —       —       (7,016,672 )
 
Proceeds from sale of assets
     248,623       2,003,052       —       —       —  
 
Investment in accounts receivable, other
     —       —       —       (2,774,087 )     —  
 
Investment in notes receivable
     (4,676,721 )     (3,330,000 )     (899,574 )     (653,632 )     —  
 
Collection of notes receivable
     —       5,675,345       2,380,000       2,380,000       924,441  
 
Net cash settlements on oil and natural gas swaps
     —       —       (3,530,651 )     (3,530,651 )     (2,182,065 )
                               
   
Net cash provided by (used in) investing activities
     (8,474,770 )     1,023,246       (68,964,738 )     (70,076,259 )     (53,827,427 )
                               
Cash flows from financing activities:
                                        
 
Proceeds from long-term debt
     13,955,000       12,808,708       56,573,000       56,573,000       112,800,000  
 
Payments of long-term debt
     (9,260,000 )     (17,293,708 )     (6,100,000 )     (2,700,000 )     (73,189,791 )
 
Payment of debt issuance costs
     —       —       (867,756 )     (874,520 )     (292,803 )
 
Proceeds from subordinated notes payable — partners
     —       —       14,264,360       14,264,360       —  
 
Proceeds from issuance of units, net
     —       —       —       —       77,894,654  
 
Redemption of Founding Investors’ units
     —       —       —       —       (69,938,000 )
 
Dividend — Reimbursement of offering costs paid by MBN Management LLC
     —       —       —       —       (1,200,229 )
 
Capital contributed by owner
     324,691       59,527       143,690       87,506       19,356  
 
Cash not acquired in Legacy formation transaction
     —       —       —       —       (3,104,304 )
 
Distributions of capital
     (3,302,522 )     (4,532,197 )     (8,271,048 )     (6,456,770 )     (11,290,387 )
                               
   
Net cash provided by (used in) financing activities
     1,717,169       (8,957,670 )     55,742,246       60,893,576       31,698,496  
                               
   
Net increase (decrease) in cash and cash equivalents
     41,523       651,645       1,186,160       941,041       (310,696 )
 
Cash and cash equivalents, beginning of period
     75,595       117,118       768,763       768,763       1,954,923  
                               
 
Cash and cash equivalents, end of period
   $ 117,118     $ 768,763     $ 1,954,923     $ 1,709,804     $ 1,644,227  
                               
See accompanying notes to consolidated financial statements.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
CONSOLIDATED STATEMENTS OF CASH FLOWS
                                             
        Nine Months Ended
    Year Ended December 31,   September 30,
         
    2003   2004   2005   2005   2006
                     
                Unaudited
Non-Cash Investing and Financing Activities:
                                        
 
Asset retirement obligation costs and liabilities
   $ 283,922     $ (41,081 )   $ 11,816     $ (275,117 )   $ 1,467,241  
                               
 
Asset retirement obligation associated with property acquisitions
   $ —     $ —     $ 445,169     $ 445,169     $ 1,877,520  
                               
 
Distribution of oil and gas properties to owners, net
   $ 819,471     $ —     $ —     $ —     $ —  
                               
 
Contributed offering costs
   $ —     $ —     $ 155,149     $ 83,264     $ —  
                               
 
Non-controlling interests’ share of net financing costs of MBN Properties LP capitalized to oil and natural gas properties
   $ —     $ —     $ —     $ —     $ 164,202  
                               
 
Units issued to MBN Properties LP in exchange for the non-controlling interests’ share of oil and natural gas properties
   $ —     $ —     $ —     $ —     $ 31,743,934  
                               
 
Units issued to Brothers Group in exchange for:
                                        
   
Oil and natural gas properties and other assets
   $ —     $ —     $ —     $ —     $ 105,298,794  
                               
   
Other property and equipment
   $ —     $ —     $ —     $ —     $ 107,275  
                               
 
Units issued to H2K Holdings Ltd. in exchange for oil and natural gas properties
   $ —     $ —     $ —     $ —     $ 1,419,483  
                               
 
Oil and natural gas hedge liabilities assumed from the Brothers Group and H2K Holdings Ltd. 
   $ —     $ —     $ —     $ —     $ 3,147,152  
                               
 
Units issued to Henry Holding LP in exchange for oil and natural gas properties
   $ —     $ —     $ —     $ —     $ 2,346,000  
                               
 
Deemed dividend to Moriah Group owners for accounts not acquired in Legacy formation transaction:
                                        
   
Accounts receivable, oil and natural gas
   $ —     $ —     $ —     $ —     $ 4,248,157  
                               
   
Accounts receivable, joint interest owners
   $ —     $ —     $ —     $ —     $ 249,627  
                               
   
Accounts receivable, other
   $ —     $ —     $ —     $ —     $ 539,968  
                               
   
Other assets
   $ —     $ —     $ —     $ —     $ 891,300  
                               
   
Accounts payable
   $ —     $ —     $ —     $ —     $ (213,941 )
                               
   
Accrued oil and natural gas liabilities
   $ —     $ —     $ —     $ —     $ (1,520,709 )
                               
   
Due to affiliates
   $ —     $ —     $ —     $ —     $ (1,254,215 )
                               
   
Other liabilities
   $ —     $ —     $ —     $ —     $ (2,166,276 )
                               
See accompanying notes to consolidated financial statements.

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Table of Contents

LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
     (a) Organization, Basis of Presentation and Description of Business
      On March 15, 2006, Legacy Reserves LP (“LRLP” or “Legacy”), as the successor entity to the Moriah Group (defined below), completed a private equity offering in which it (1) issued 5,000,000 limited partnership units at a gross price of $17.00 per unit, netting $77.9 million after initial purchaser’s discount, placement agent’s fee and expenses, (2) acquired certain oil and natural gas properties (Note 3) and (3) redeemed 4.4 million units for $69.9 million from certain of its Founding Investors. The Moriah Group has been treated as the acquiring entity in this transaction, hereinafter referred to as the “Legacy Formation.” Because the combination of the businesses that comprised the Moriah Group was a reorganization of entities under common control, the combination of these businesses has been reflected retroactively at carryover basis in these consolidated financial statements. The accounts presented for periods prior to the Legacy Formation transaction are those of the Moriah Group.
      LRLP and its affiliated entities are referred to as Legacy in this document.
      LRLP, a Delaware limited partnership, was formed by its general partner, Legacy Reserves GP, LLC (“LRGPLLC”), on October 26, 2005 to own and operate oil and natural gas properties. LRGPLLC is a Delaware limited liability company formed on October 26, 2005, and it owns a 0.1% general partner interest in LRLP.
      Significant information regarding rights of the limited partners includes the following:
  •  Right to receive distributions of available cash within 45 days after the end of each quarter.
 
  •  No limited partner shall have any management power over our business and affairs; the general partner shall conduct, direct and manage LRLP’s activities.
 
  •  The general partner may be removed if such removal is approved by the unitholders holding at least 662/3 percent of the outstanding units, including units held by LRLP’s general partner and its affiliates.
 
  •  Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year
      In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and LRLP’s general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
      As used herein, the term Moriah Group refers to Moriah Resources, Inc. (“MRI”), Moriah Properties, Ltd. (“MPL”), the oil and natural gas interests individually owned by Dale A. and Rita Brown and the accounts of MBN Properties LP on a consolidated basis unless the context specifies otherwise. Prior to March 15, 2006, the accompanying financial statements include the accounts of the Moriah Group. From March 15, 2006, the accompanying financial statements also include the results of operations of the oil and natural gas properties acquired in the Legacy Formation transaction. All significant intercompany accounts and transactions have been eliminated. The Moriah Group consolidated MBN Properties LP as a variable interest entity under FASB FIN 46R since the Moriah Group was the primary beneficiary of MBN Properties LP. The partners, shareholders and owners of these entities have other investments, such as real estate, that are held either individually or through other legal entities that are not presented as part of these financial statements. The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred.
      MRI was organized as a sub-chapter S corporation on September 28, 1992 under the laws of the State of Texas, and serves as the 1% general partner to MPL. MPL was organized as a limited partnership on July 1, 1999 under the laws of the State of Texas. Dale A. Brown, an individual, has owned oil and natural gas

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
working interests since 1981. Dale A. Brown, who along with his son, Cary D. Brown, are the sole owners of MRI and MPL. The assets of Moriah Properties New Mexico, Ltd. (“MNM”), a limited partnership organized under the laws of the State of Texas on October 17, 2003, were assigned into MPL effective September 1, 2005, in order to streamline the business of the limited partnerships with identical ownership and a shared general partner, MRI, and the accounts of MNM have been reflected retroactively in the financial statements of MPL. Effective October 1, 2005, Dale and Rita Brown assigned the selected oil and natural gas properties included in these consolidated financial statements to DAB Resources, Ltd., a Texas limited partnership they own.
      On July 22, 2005, MPL advanced $1,649,132 in the form of paid in capital and subordinated notes receivable to MBN Properties LP which utilized the capital to fund a deposit with The Prospective Investment and Trading Company, Ltd. (“PITCO”) and its affiliates for the purchase of oil and natural gas properties described below. MPL also advanced $654,099 to fund the expenses of MBN Management LLC, the general partner of MBN Properties LP. Of this amount, $467 was for paid in capital and the balance of $653,632 was in a note receivable from MBN Management LLC. MBN Properties LP, a Delaware limited partnership, and MBN Management LLC, a Delaware limited liability company, (collectively the “MBN Group”) were formed to acquire and operate oil and natural gas producing properties in partnership with Brothers Production Properties, Ltd., and certain third party investors. Cary D. Brown, the Executive Vice President of MRI and its 50% owner, is the Chief Executive Officer and a Director of MBN Management LLC. On September 14, 2005, MBN Properties LP purchased oil and natural gas producing properties located in the Permian Basin from PITCO and its affiliates for $66,151,723 (the “PITCO Acquisition”), subject to post-closing adjustments. While MBN Management LLC is a variable interest entity, the Moriah Group accounted for its interest in that entity using the equity method since it is not the primary beneficiary of MBN Management LLC under the expected losses test of paragraph 14 of FAS FIN 46R.
      Legacy owns and operates oil and natural gas producing properties located primarily in the Permian Basin of West Texas and southeast New Mexico. Legacy has acquired oil and natural gas producing properties and drilled leasehold.
     (b) Cash Equivalents
      For purposes of the combined statement of cash flows, Legacy considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.
     (c) Trade Accounts Receivable
      Trade accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 12).
     (d) Oil and Natural Gas Properties
      Legacy accounts for oil and natural gas properties by the successful efforts method. Under this method of accounting, costs relating to the acquisition of and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities.
      Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. FAS No. 19 requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped, and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by the Legacy’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 13, Legacy follows FAS No. 143. Under FAS No. 143, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates.
      Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation.
      Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy assesses impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using oil and natural gas prices as of the last day of the statement period held constant. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2004 and 2005, the estimated undiscounted future cash flows for Legacy’s proved oil and natural gas properties exceeded the net capitalized costs, and no impairment was required to be recognized. In 2003, impairment of $471,394 was recognized when a dry hole was drilled on the Mountain Cat Prospect and the remainder of the unproved acreage was written off. For the nine months ended September 30, 2006, Legacy recognized $8.6 million of impairment expense on 22 separate producing fields related primarily to the decline in natural gas prices from the dates at which the purchase prices for the PITCO acquisition and the formation transaction were allocated among the purchased properties. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Costs related to unproved mineral interests that are individually insignificant are amortized over the shorter of the exploratory period or the lease/concession holding period which is typically three years in the Permian Basin.
     (e) Oil and Natural Gas Reserve Quantities
      Legacy’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche Petroleum Consultants, Ltd. prepares a reserve and economic evaluation of all Legacy’s properties on a well-by-well basis utilizing information provided to it by Legacy and utilizing information available from state agencies that collect information reported to it by the operators of Legacy’s properties.
      Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve report. The accuracy of Legacy’s reserve

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
      Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.
     (f) Income Taxes
      No provision for income taxes is made in Legacy’s consolidated financial statements because the taxable income or loss of Legacy is included in the income tax returns of the individual owners.
     (g) Derivative Instruments and Hedging Activities
      Legacy periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. Legacy accounts for these activities pursuant to FAS No. 133 — Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.
      Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices. Therefore, the mark-to-market of these instruments is recorded in current earnings (see Note 10).
     (h) Use of Estimates
      Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these combined financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the combined financial statements include estimates of oil and natural gas reserves, valuation of derivatives, future cash flows from oil and natural gas properties, depreciation, depletion and amortization and asset retirement obligations.
     (i) Revenue Recognition
      Sales of crude oil and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of Legacy’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. As a result, Legacy’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. Legacy believes that the pricing provisions of its oil and natural gas contracts are customary in the industry.
      We currently use the “net-back” method of accounting for transportation arrangements of our natural gas sales. We sell natural gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by our purchasers and reflected in the wellhead price. Our contracts with respect to the sale of our natural gas produced, with one

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
immaterial exception, provide us with a net price payment. That is, when we are paid for our natural gas by our purchasers, we receive a price which is net of any costs incurred for treating, transportation, compression, etc. In accordance with the terms of our contracts, the payment statements we receive from our purchasers show a single net price without any detail as to treating, transportation, compression, etc. Thus, our revenues are recorded at this single net price.
      Natural gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant natural gas imbalance positions as of December 31, 2004 or 2005 or September 30, 2006.
      We are paid a monthly operating fee for each well we operate for outside owners. The fee covers monthly general and administrative costs. As the operating fee is a reimbursement of costs incurred on behalf of third parties, the fee has been netted against general and administrative expense.
     (j) Investments
      Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest are accounted for by the equity method. Under the equity method, our investments are stated at cost plus the equity in undistributed earnings and losses after acquisition.
     (k) Intangible assets
      Legacy has capitalized certain operating rights acquired in the acquisition of oil and gas properties (Note 5). The operating rights, which have no residual value, will be amortized over their estimated economic life of approximately 15 years beginning July 1, 2006. Amortization expense will be included as an element of depletion, depreciation, amortization and accretion expense. Impairment will be assessed on a quarterly basis or when there is a material change in the remaining useful life. The expected amortization expense for 2007, 2008, 2009, 2010 and 2011 is $588,000, $547,000, $537,000, $522,000 and $510,000, respectively.
     (l) Environmental
      Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require Legacy 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. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments are fixed and readily determinable.
     (m) Earnings Per Unit
      Legacy computes its earnings per unit in accordance with SFAS No. 128, Earnings per Share, which requires the presentation of basic and diluted earnings per unit on the face of the income statement. Basic earnings per unit amounts are calculated using the average number of units outstanding during each period. Diluted earnings per unit also gives effect to restricted units (calculated based upon the treasury stock method). Legacy does not present diluted earnings per unit for periods in which it incurred net losses as the effect is antidilutive.
      Basic and diluted earnings per unit for the years ended December 31, 2003, 2004 and 2005 and the nine-month period ended September 30, 2005 were computed based on the 9,488,921 units issued to the

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
Moriah Group on March 15, 2006 in exchange for oil and natural gas properties contributed by it (including its indirect interest in oil and natural gas properties contributed by MBN Properties, LP) in conjunction with the closing of the Legacy Formation on the same date. Basic and diluted earnings per unit for the nine-month period ended September 30, 2006 are computed based on the weighted average number of units outstanding during that period, including the 9,488,921 units issued to the Moriah Group on March 15, 2006 for the 73 days from January 1, 2006 through March 14, 2006, 18,240,067 units for the 29 days from March 15, 2006 through April 12, 2006, 18,248,817 units for the 78 days from April 13, 2006 through June 29, 2006 and 18,386,817 for June 30, 2006 through September 30, 2006. No transactions have occurred subsequent to September 30, 2006 which would have changed materially the number of units or potential units outstanding at September 30, 2006.
(n)             Redemption of Units
      Units redeemed are recorded at cost.
(o)             Segment Reporting
      Legacy operates as one business segment within the Permian Basin region. Upon the closing of the PITCO Acquisition on September 14, 2005, the acquisition of the oil and natural gas properties of the Brothers Group, H2K Holdings Ltd. and the Charitable Support Foundations, Inc. and its affiliates on March 15, 2006, the June 29, 2006 acquisition of oil and natural gas properties in the South Justice Unit from Henry Holding LP, the June 29, 2006 acquisition of oil and natural gas properties in the Farmer Field from Larron Oil Corporation and the July 31, 2006 acquisition of certain oil and natural gas properties from Kinder Morgan, operating segments were created for each group of oil and natural gas properties. Legacy aggregates these operating segments into a single segment for reporting purposes.
(p) Unit-Based Compensation
      Concurrent with the Formation Transaction on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created and Legacy adopted SFAS No. 123(R), Share-Based Payment. This statement requires companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period for the award. Since Legacy had no restricted or option unit awards prior to March 15, 2006, there were no adoption or transition consequences as contemplated by SFAS No. 123(R). Pursuant to the provisions of SFAS 123(R), Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at September 30, 2006 does not include 65,116 units related to unvested restricted unit awards. Since Legacy is a flow-through entity for tax purposes, there will be no effect from the requirement by SFAS No. 123(R) that the benefits of tax deductions in excess of recognized compensation cost be reflected as a financing cash flow, rather than as an operating cash flow as currently required.
(q) Interim Financial Statements
      The consolidated financial statements as of and for the nine months ended September 30, 2006 and 2005 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) have been condensed or omitted in these financial statements for and as of the nine months ended September 30, 2005 and 2006.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
     (r)  Recently Issued Accounting pronouncements
      Emerging Issues Task Force (“EITF”) Issue 04-9 and Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) FAS 19-1: Statement of Financial Accounting Standards (“FAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” requires the cost of drilling an exploratory well to be capitalized pending determination of whether the well has found proved reserves. If this determination cannot be made at the conclusion of drilling, FAS No. 19 sets out additional requirements for continuing to carry the cost of the well as an asset. These requirements include firm plans for further drilling and a one-year time limitation on continued capitalization in certain instances. In April 2005, the FASB issued FSP FAS 19-1, which was adopted effective January 1, 2005. This FSP amends FAS No. 19 to allow continued capitalization when (a) the well has found a sufficient quantity of reserves to justify proceeding with the project plan and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project which may include more than one exploratory well if the reserves are intended to be extracted in a single integrated operation. The FSP also requires increased disclosures. Adoption of this rule did not have a material impact on our consolidated earnings in 2005. If this FSP had been applied to 2004, it would not have had a material effect on our earnings for that year.
      FAS No. 154: In 2005, the FASB issued FAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FAS No. 3,” which is effective January 1, 2006. Opinion 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This Statement requires retrospective application (restatement) to prior periods’ financial statements of changes in accounting principle. This Statement also applies to changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.
      FAS Interpretation No. 47: In March 2005, the FASB issued FAS Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FAS Statement No. 143,” “Accounting for Asset Retirement Obligations,” which is effective no later than December 31, 2005. This pronouncement clarifies that the term “conditional asset retirement obligation” as used in FAS Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. This interpretation is not expected to have a material impact on either our earnings or consolidated balance sheet.
      In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 is effective for fiscal years ending after November 15, 2006, and early application is encouraged. Legacy does not believe SAB 108 will have a material impact on our financial position or results of operations.
      In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“FAS 157”). This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted account principles and expands disclosure related to the use of fair value measures in financial statements. The Statement is to be effective for Legacy’s financial statements issued in 2008; however, earlier application is encouraged. The Statement will affect fair value measurements we make after adoption. Legacy is currently evaluating the timing of adoption.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
(2) Fair Values of Financial Instruments
      The estimated fair values of Legacy’s financial instruments closely approximate the carrying amounts as discussed below:
        Cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.
 
        Notes receivable. The carrying amounts approximate fair value due to the comparability of the interest rate to market interest rates for instruments of similar terms and credit quality.
 
        Debt. The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings.
 
        Commodity price derivatives. The fair market values of commodity derivative instruments are estimated based upon the current market price of the respective commodities at the date of valuation. It represents the amount which Legacy would be required to pay or able to receive, based upon the differential between a fixed and a variable commodity price as specified in the hedge contracts.
(3) Notes Receivable — Affiliated Entities
      Notes receivable were issued to affiliated entities involved in commercial real estate and other investments. These notes bore interest at market rates and were secured by the associated real estate where applicable. The table below sets forth the notes receivable as of December 31, 2003 and 2004 and 2005. Each of these notes was paid in full during the year after issuance.
                         
    December 31,
     
    2003   2004   2005
             
Real Estate Deed of Trust note receivable bearing interest at bank prime plus 3.5% due on October 31, 2007
   $ 4,725,345     $ —     $ —  
Real Estate Deed of Trust note receivable bearing interest at bank prime plus 3.5% due on March 31, 2015
     —       2,230,000       —  
Note receivable bearing interest at bank prime due January 3, 2005 — unsecured
     —       150,000       —  
                   
    $ 4,725,345     $ 2,380,000     $ —  
                   
(4) Credit Facility
      On July 29, 1999, the Moriah Group entered into a Credit Facility (the Agreement) that permitted borrowings up to the lesser of (i) the borrowing base, or (ii) $20 million. The borrowing base was originally set at $8 million, was re-determined annually by the lender and decreased monthly based upon a schedule determined by the terms of the Agreement. Borrowings under the Agreement bore interest at a rate equal to the three-month LIBOR plus an add-on rate which increased from a minimum of 2.0% to a maximum of 3.5% based upon the amount borrowed as a percentage of the borrowing base with the interest payable monthly. The Agreement was secured by substantially all the oil and natural gas assets of the Moriah Group. The Moriah Group had $7.2 million available on the borrowing base and had $2.0 million outstanding at a rate of 4.1% as of December 31, 2004. The Moriah Group paid interest expense on this debt of $74,567, $239,324 and $18,323 for the years ended December 31, 2003, 2004 and 2005, respectively.
      The Agreement provided for certain restrictions, including but not limited to, limitations on additional borrowings, restrictions on use of proceeds, sales of collateral, and distributions to owners. It also required

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
the Moriah Group to maintain certain quarterly debt service ratios. At December 31, 2004, the Moriah Group was in compliance with all aspects of the Agreement.
      Long-term debt consists of the following at December 31, 2005 and September 30, 2006:
                 
    December 31,   September 30,
    2005   2006
         
MPL — due September 2009
   $ 20,723,000     $ —  
MBN Properties LP — due September 2007
     31,750,000       —  
Legacy — due March 2010
     —       106,800,000  
             
    $ 52,473,000     $ 106,800,000  
             
      On September 13, 2005, the Moriah Group replaced its Credit Agreement with a new Senior Credit Facility (the New Facility) with a new lending group that permitted borrowings in the lesser amount of (i) the borrowing base, or (ii) $75 million. The borrowing base under the New Facility, initially set at $40 million, was subject to re-determination every six months and was subject to adjustment based upon changes in the fair market value of the Moriah Group’s oil and natural gas assets. Interest on the New Facility was payable monthly and was charged in accordance with the Moriah Group’s selection of a LIBOR rate plus 1.5% to 2.0%, or prime rate up to prime rate plus 0.5%, dependent on the percentage of the borrowing base which was drawn. Borrowings under this New Facility were due in September 2009. The New Facility contained certain loan covenants requiring minimum financial ratio coverages, involving the current ratio and EBITDA to interest expense. On September 13, 2005, the Moriah Group borrowed $22,123,000 from the new lending group to provide for general corporate purposes, to fund a $4.2 million distribution to Cary Brown and Dale Brown and to advance additional subordinated notes receivable in the amount of $17,598,000 to MBN Properties LP, which purchased oil and natural gas producing properties from PITCO. The Moriah Group’s interest rate at December 31, 2005 was 6.0%. The Moriah Group paid interest expense on this debt of $220,638 for the year ended December 31, 2005. All amounts outstanding under this agreement at March 15, 2006 were repaid in full on that date as part of the formation transactions.
      On September 13, 2005, MBN Properties LP entered into a Credit Agreement with a new Senior Credit Facility (the MBN Facility) with a lending group that permitted borrowings in the lesser amount of (i) the borrowing base, or (ii) $75 million. The borrowing base under the MBN Facility, initially set at $35 million, was subject to re-determination every six months and was subject to adjustment based upon changes in the fair market value of the MBN Properties LP’s oil and natural gas assets. Interest on the MBN Facility was payable monthly and was charged in accordance with MBN Properties LP’s selection of a LIBOR rate plus 1.5% to 2.0%, or prime rate up to prime rate plus 0.50%, dependent on the percentage of the borrowing base which was drawn. Borrowings under this MBN Facility were due in September 2007. The MBN Facility contained certain loan covenants requiring minimum financial ratio coverages, involving the current ratio and EBITDA to interest expense. On September 13, 2005, MBN Properties LP borrowed $33,750,000 from the new lending group to purchase oil and natural gas producing properties from PITCO. The MBN Properties LP’s interest rate at December 31, 2005 was 6.33%. MBN Properties LP paid interest expense of $431,085 on this debt for the period from inception to December 31, 2005. All amounts outstanding under this agreement at March 15, 2006 were repaid in full on that date as part of the formation transactions.
      As an integral part of the Legacy Formation, Legacy entered into a new credit agreement with a new senior credit facility (the “Legacy Facility”) with the same lending group that participated in the New Facility of the Moriah Group. Legacy’s oil and natural gas properties are pledged as collateral for any borrowings under the Legacy Facility. The terms of the Legacy Facility permits borrowings in the lesser amount of (i) the borrowing base, or (ii) $300 million. The borrowing base under the Legacy Facility, initially set at $130 million, is re-determined every six months and will be adjusted based upon changes in the fair market value of the Partnership’s oil and natural gas assets. Interest on the Legacy Facility is payable monthly

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
and is charged in accordance with the Partnership’s selection of a LIBOR rate plus 1.25% to 1.875%, or prime rate up to prime rate plus 0.375%, dependent on the percentage of the borrowing base which is drawn. On March 15, 2006, Legacy borrowed $65.8 million from the new lending group as part of the Legacy Formation. On June 6, 2006, Legacy’s bank group reaffirmed our $130 million borrowing base. As of September 30, 2006, Legacy had outstanding borrowings of $106.8 million at an interest rate of 7.21%. Thus, we had approximately $23.2 million of availability remaining. For the period from March 15, 2006 through September 30, 2006, Legacy paid $2,908,913 of interest expense on the Legacy Facility. The Legacy Facility contains certain loan covenants requiring minimum financial ratio coverages, involving the current ratio and EBITDA to interest expense. At September 30, 2006, Legacy was in compliance with all aspects of the Legacy Facility.
(5) Acquisitions
Energen Resources Acquisition
      In March 2003, Moriah Properties, Ltd. acquired from Energen Resources an additional working interest in the SE Stinnett Unit and the Jordan University Unit for approximately $400,000 cash.
Pure Acquisition
      Effective May 1, 2003, Moriah Properties, Ltd. acquired from Pure Resources a working interest in oil and natural gas properties for approximately $337,000. These properties consist of 68 wellbores located in the Iatan, East Howard field of Mitchell County, Texas. These properties are operated by Brothers Production Company Inc., and the acquisition was funded with cash.
Langlie Mattix Acquisition
      Effective October 1, 2003, Moriah Properties, Ltd. acquired from Pecos Production Company an operated working interest in the Langlie Mattix Penrose Sand Unit (“LMPSU”) located in Lea County, New Mexico for approximately $1.36 million. The property is operated by Moriah Resources, Inc. and the acquisition was funded with cash.
Denton Devonian Acquisition
      Effective April 1, 2004, Moriah Properties, Ltd. acquired from Fasken Oil and Ranch an additional working interest in the JM Denton lease for approximately $580,000. This property is operated by Brothers Production, Inc. Also acquired were working interests in a Fasken operated lease for approximately $1.1 million. Both of these leases are located in the Denton Devonian field in Lea County, New Mexico. This acquisition consisted of interests in 16 wellbores. The acquisition was funded with cash.
PITCO Acquisition
      On September 14, 2005, MBN Properties LP purchased oil and natural gas producing properties located in the Permian Basin from PITCO and its affiliates for $66,151,723 (the “PITCO Acquisition”), subject to post-closing adjustments estimated to be approximately $2.8 million. The all cash acquisition was funded from borrowings of $33,750,000 under MBN Properties LP’s existing credit facility and from loans from MPL and the Brothers Group (see Note 6). Including direct expenses associated with the PITCO acquisition, MBN Properties LP has recorded a purchase price of approximately $63.9 million, all of which has been allocated to the oil and natural gas properties purchased. In addition, MBN Properties LP has recorded a $445,000 asset retirement obligation (“ARO”) and related ARO asset under the guidelines of FAS 143. The results of operations from the properties acquired in the PITCO acquisition have been included in Legacy’s statements of operations beginning September 14, 2005.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
      Legacy Formation Acquisition
      On March 15, 2006, LRLP completed a private equity offering in which it issued 5,000,000 limited partnership units at a gross price of $17.00 per unit, netting $78.7 million after initial purchaser’s discount, placement agent fees and expenses. Simultaneous with the completion of this offering, Legacy purchased the oil and natural gas properties of the Moriah Group, Brothers Group, H2K Holdings Ltd. and the Charitable Support Foundations, Inc. and its affiliates. Legacy also purchased the oil and natural gas properties owned by MBN Properties, LP. In the case of the Moriah Group, the Brothers Group and H2K Holdings Ltd. those entities exchanged their oil and natural gas properties for limited partnership units. The purchase of the oil and natural gas properties owned by the charitable foundations was solely for cash of $7.7 million. The owners of the Moriah Group, the Brothers Group and H2K Holdings Ltd. (the “Founding Investors”) exchanged 4.4 million of their units for $69.9 million in cash. The Moriah Group has been treated as the acquiring entity in the Legacy Formation. Accordingly, the accounts of the businesses acquired from the Moriah Group have been reflected retroactively at carryover basis in the consolidated financial statements, and the units issued to acquire them have been accounted for as a recapitalization. The net assets of the other businesses acquired and the units issued in exchange for them have been reflected at fair value and included in the statement of operations from the date of acquisition. With the exception of its assumption of liabilities associated with the oil and natural gas swaps it acquired, the other depreciable assets of the Brothers Group (office furniture and equipment and vehicles) and certain unamortized deferred financing costs of the Moriah Group, LRLP did not acquire any other assets or liabilities of the Moriah Group, the Brothers Group, H2K Holdings Ltd. or the Charitable Support Foundations, Inc. and its affiliates. The removal of the other assets and liabilities of the Moriah Group was reflected as a deemed dividend in Legacy’s September 30, 2006 consolidated statement of unitholders’ equity.
      The following table sets forth the units issued in the Legacy Formation transaction:
             
    Number of Units
     
MPL
     7,334,070  
DAB Resources, Ltd. 
     859,703  
       
 
Moriah Group
     8,193,773  
Brothers Group
     6,200,357  
H2K Holdings Ltd. 
     83,499  
MBN Properties LP
     3,162,438  
LRLP units
     600,000  
       
   
Total units issued at Legacy Formation
     18,240,067  
       
      In addition to the 18,240,067 units issued at Legacy Formation, 52,616 restricted management units were issued to employees of Legacy concurrent with, but not as a part of, the Legacy Formation (Note 11).

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
      The following table sets forth the purchase price of the oil and natural gas properties purchased from the Brothers Group, H2K Holdings Ltd. and three charitable foundations, which included the assumption of liabilities associated with oil and natural gas swaps as of March 14, 2006:
                     
    Number of Units   Purchase Price
    at $17.00 per Unit   of Assets Acquired
         
Brothers Group
     6,200,357     $ 105,406,069  
H2K Holdings Ltd. 
     83,499       1,419,483  
Cash paid to three charitable foundations
     —       7,682,854  
             
 
Total purchase price before liabilities assumed
             114,508,406  
Plus:
                
 
Oil and natural gas swap liabilities assumed
             3,147,152  
 
Asset retirement obligations incurred
             1,467,241  
Less:
                
 
Office furniture, equipment and vehicles acquired
             (107,275 )
             
   
Total purchase price allocated to oil and natural gas properties acquired
           $ 119,015,524  
             
      In addition to the 3,162,438 common units issued to MBN Properties LP as part of the Legacy Formation transaction, LRLP paid $65.3 million in cash to MBN Properties LP to acquire that portion of the oil and natural gas properties of MBN Properties LP it did not already own by virtue of the Moriah Group’s ownership of a 46.22% limited partnership interest in MBN Properties LP. In addition, LRLP paid $1,980,468 to MBN Management LLC to reimburse expenses incurred by that entity in anticipation of the Legacy Formation. The following table sets forth the calculation of the step-up of oil and natural gas property basis with respect to this interest acquired:
                   
    Number of Units   Purchase Price of
    at $17.00 per Unit   Assets Acquired
         
Units issued to MBN Properties LP
     3,162,438     $ 53,761,446  
Cash paid to MBN Properties LP
     —       65,300,000  
             
 
Total purchase price before liabilities assumed
             119,061,446  
Plus:
                
 
Oil and natural gas swap liabilities assumed
             2,539,625  
 
ARO liabilities assumed
             453,913  
Less:
                
 
Net book value of other property and equipment on MBN Properties LP at March 14, 2006
             (39,056 )
             
              122,015,928  
Less:
                
 
Net book value of oil and gas assets on MBN Properties LP at March 14, 2006
             (62,990,390 )
             
Purchase price in excess of net book value of assets
             59,025,538  
Less:
                
 
Share already owned by Moriah via consolidation of MBN Properties LP
     46.22 %     (27,281,604 )
             
Non-controlling interest share to record
             31,743,934  

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
                     
    Number of Units   Purchase Price of
    at $17.00 per Unit   Assets Acquired
         
Plus:
                
 
Elimination of deferred financing costs related to non-controlling interests’ share of MBN Properties LP
             164,202  
 
Reimbursement of Brothers Group’s share of MBN Management LLC losses from inception through March 14, 2006
             780,239  
             
MBN Properties LP purchase price to allocate to oil and natural gas properties
           $ 32,688,375  
             
Units related to purchase of non-controlling interest
     1,867,290          
Units related to interest previously owned by Moriah Group
     1,295,148          
             
   
Total units issued to MBN Properties LP
     3,162,438          
             
      Larron Acquisition
      On June 29, 2006, Legacy purchased a 100% working interest and an approximate 82% net revenue interest in producing leases located in the Farmer Field for $5,700,000 before post-closing adjustments which will not be finally determined until Larron Oil Corporation provides the required post-closing settlement statement. The conveyance of the leases is effective April 1, 2006. The leases acquired include 49 active oil wells and one water injection well. The estimated $5.6 million net purchase price was allocated with $4.6 million recorded as lease and well equipment and $1.0 million of leasehold costs. Asset retirement obligations in the amount of $328,867 were recognized in connection with this acquisition.
      South Justis Unit Acquisition
      On June 29, 2006, Legacy purchased Henry Holding LP’s 15.0% working interest and a 13.1% net revenue interest in the South Justis Unit (“SJU”), two leases not in the unit, each with one well, adjacent to the SJU and the right to operate these properties. The stated purchase price was $14 million cash plus the issuance of 138,000 units on June 29, 2006 and 8,415 units on November 10, 2006 at their estimated fair value of $17.00 per unit ($2,346,000 and $143,055, respectively) less final adjustments of approximately $624,000. The effective date of our ownership is May 1, 2006. For purposes of Legacy’s statement of operations for the nine months ended September 30, 2006, the operating results from this acquisition have been included from July 1, 2006. The properties acquired are located in Lea County, New Mexico where we own other producing properties. The acquired properties include 113 active producing wells supported by 97 water injection wells in this waterflood unit. Legacy has been elected operator of the SJU following the closing of the transaction, which entitles Legacy to a contractual overhead reimbursement of approximately $127,500 per month from its partners in the SJU. The estimated $15.8 million net purchase price was allocated (not including the $143,055 relating to the 8,415 units issued November 10, 2006) with $2.9 million recorded as lease and well equipment, $5.9 million of leasehold costs and $7.0 million capitalized as an intangible asset relating to the contract operating rights. The capitalized operating rights will be amortized over the estimated total well months the wells in the SJU are expected to be operated. Asset retirement obligations in the amount of $137,453 were recognized in connection with this acquisition.
      Kinder Morgan Acquisition
      On July 31, 2006, Legacy purchased certain oil and natural gas properties located in the Permian Basin from Kinder Morgan for an estimated net purchase price of $17.3 million. The effective date of this purchase was July 1, 2006. The post-closing adjustments to the purchase price have not yet been determined. The estimated $17.3 million purchase price was allocated with $4.6 million recorded as lease and well equipment

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
and $12.7 million of leasehold costs. Asset retirement obligations of $1,383,180 were recorded in connection with this acquisition.
      Pro Forma Operating Results
      The following table reflects the unaudited pro forma results of operations as though the PITCO acquisition had occurred on January 1, 2004 and 2005 and the Formation Transactions and the Farmer Field, South Justis Unit and Kinder Morgan acquisitions had each occurred on January 1, 2005 and 2006. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:
                                 
        Nine Months Ended
    Year Ended December 31,   September 30,
         
    2004   2005   2005   2006
                 
    (In thousands)
Revenues, excluding hedging gains and losses
   $ 27,776     $ 64,128     $ 46,242     $ 53,353  
                         
Revenues, net of hedging gains and losses
   $ 27,143     $ 53,080     $ 32,846     $ 57,582  
                         
Income from continuing operations
   $ 8,606     $ 6,295     $ (139 )   $ 7,211  
                         
Net income
   $ 8,628     $ 6,295     $ (139 )   $ 7,211  
                         
                                   
Earnings per unit - basic and diluted:                
 
Income from continuing operations
   $ 0.91     $ 0.34     $ (0.01 )   $ 0.39  
                         
 
Net Income
   $ 0.91     $ 0.34     $ (0.01 )   $ 0.39  
                         
Units used in computing earnings per unit
     9,488,921       18,386,482       18,386,482       18,390,301  
                         
(6) Partnership Investments
Accord Partnership
      In November 2002, Legacy purchased a combined 34.7% interest in Accord Resources, Ltd, (“Accord”), a partnership formed specifically to acquire various working interests in oil and natural gas properties located in Wise, Young and Jack County, Texas. Legacy’s cash investment in Accord was approximately $467,000 and was accounted for by the equity method. Moriah Resources, Inc. was the general partner of Accord and responsible for daily operation of the properties.
      Cash distributions received by Legacy from the partnership for the years ended December 31, 2003 and 2004 were approximately $138,600 and $103,950, respectively. Effective March 31, 2004, Accord was dissolved and the interests in the oil and natural gas properties were distributed to each of the partners, including Legacy. On April 1, 2004, in conjunction with the other Accord partners, Legacy sold all of its interests in the oil and natural gas properties to Aspen Integrated Oil and Gas, L.L.C. for approximately $2.0 million resulting in a gain on sale of assets of approximately $1.3 million.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
      The following table reflects net income information for the Accord Partnership on a gross basis:
                   
        Three Months
    Year Ended   Ended
    December 31,   March 31,
    2003   2004
         
Oil and natural gas revenues
   $ 4,637,443     $ 1,129,819  
Oil derivative expense
     (254,440 )     —  
Other operating revenues
     178,505       174,517  
Direct lease operating expenses
     (2,162,386 )     (431,595 )
Production taxes
     (309,431 )     (71,105 )
Depletion, depreciation and accretion
     (927,467 )     (129,873 )
Other expenses
     (186,629 )     (7,958 )
             
 
Operating income
     975,595       663,805  
Other expense
     (76,996 )     (134,298 )
             
 
Partnership net income
   $ 898,599     $ 529,507  
             
     MBN Properties LP and MBN Management LLC
      MBN Properties LP, a Delaware limited partnership, and its 1% general partner, MBN Management LLC, a Delaware limited liability company, (collectively the “MBN Group”) were formed in 2005 to acquire and operate oil and natural gas producing properties in partnership with Brothers Production Properties, Ltd., and certain third party investors. On July 22, 2005, MPL advanced $1,649,132 in the form of $462 of paid in capital (46.2% partnership equity interest) and subordinated notes receivable of $1,648,670 to MBN Properties LP which utilized the capital to fund a deposit with The Prospective Investment and Trading Company, Ltd. (“PITCO”) and its affiliates for the purchase of oil and natural gas properties described in Note 5 above. On September 13, 2005, MPL advanced MBN Properties LP an additional $17,598,000 under the subordinated note receivable in conjunction with the closing of the PITCO acquisition described in Note 5 above. The subordinated note receivable from MBN Properties LP was due on July 15, 2012 and bore interest payable quarterly at the rate the Moriah Group paid under its New Facility plus 4%. The other investors in MBN Properties, LP loaned money on similar terms. The notes payable to the other investors (which have not been eliminated in consolidation) are reflected as subordinated notes payable-partners in the accompanying consolidated balance sheet. MPL also advanced $654,099 to fund the expenses of MBN Management LLC, the general partner of MBN Properties LP. Of this amount, $467 was for paid in capital (46.7% partnership equity interest) and the balance of $653,632 was in a subordinated note receivable from MBN Management LLC due July 15, 2012 and bearing interest at 7%. At December 31, 2005, MBN Properties LP had a payable to MBN Management LLC in the amount of $194,907 related to advances made to MBN Properties LP during the period from inception through December 31, 2005. All amounts owned by MBN Properties LP and MBN Management LLC to Legacy were repaid on March 15, 2006 in connection with the Formation Transactions.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
      The following tables reflect condensed balance sheet and net loss information for MBN Management LLC on a gross basis:
           
    December 31,
    2005
     
Current assets
   $ 1,233,338  
Other assets
     31,899  
       
 
Total assets
   $ 1,265,237  
       
Current liabilities
   $ 640,727  
Notes payable-affiliated entities
     1,952,753  
Members’ deficit
     (1,328,243 )
       
 
Total liabilities and members’ deficit
   $ 1,265,237  
       
                   
    From Inception    
    Through    
    December 31,   January 1, 2006
    2005   to March 14, 2006
         
General and administrative expenses
   $ (1,278,685 )   $ (522,569 )
             
 
Operating loss
     (1,278,685 )     (522,569 )
Other expense
     (50,558 )     (21,961 )
             
 
Net loss
   $ (1,329,243 )   $ (544,530 )
             
(7) Related Party Transactions
      Cary Brown and Dale Brown, as owners of the Moriah Group, and the Brothers Group own a combined non-controlling 18% interest as limited partners in the partnership which owns the building that Legacy occupies. Monthly rent is $6,838, without respect to property taxes and insurance. Prior to the Legacy Formation, the Moriah Group’s portion of this rent was reimbursed by the Moriah Group to Petroleum Strategies, Inc., an affiliated entity which is owned by Cary Brown and Dale Brown. The lease expires in August 2011.
      The Moriah Group did not directly employ any persons or directly incur any office overhead. Substantially all general and administrative services were provided by Petroleum Strategies, Inc. which employed all personnel and paid for all employee salaries, benefits, and office expenses. Petroleum Strategies Inc. charged the Moriah Group for such services in an amount which was intended to be equal to the actual expenses it incurred. Amounts charged were $468,513, $677,160 and $838,899 for the years ended December 31, 2003, 2004 and 2005, respectively and $491,280 and $444,827 for the nine months ended September 30, 2005 and 2006, respectively. On April 1, 2006 following the Legacy Formation, certain employees of Petroleum Strategies, Inc. and Brothers Production Company Inc. became employees of Legacy. For the period from March 15, 2006 to September 30, 2006, Brothers Production Company Inc. provided $47,236 of transition administrative services to Legacy.
      Legacy uses Lynch, Chappell and Alsup for legal services. Alan Brown, son of Dale Brown and brother of Cary Brown, is a less than ten percent shareholder in this firm. Legacy paid legal fees of $2,750, $8,904 and $23,472 for the years ended December 31, 2003, 2004 and 2005, respectively and $2,460 and $39,003 to this firm for the nine months ended September 30, 2005 and 2006, respectively.
      Legacy has $187,503 of accounts payable to MBN Properties LP with respect to oil and natural gas revenues collected by Legacy on behalf of MBN Properties LP.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
Distribution of Oil and Natural Gas Properties to Owners
      In December 2003, MPL distributed a property interest equivalent to 10% of its working interest in certain oil and natural gas properties equally to Dale Brown and Cary Brown. Subsequently, in December 2003 and January 2004, Dale and Rita Brown contributed to Charities Support Foundation Inc. (“CSFI”) and Moriah Foundation Inc. (“MFI”) and Cary and Jill Brown contributed to Charities Support Foundation Inc. and Cary Brown Family Foundation (“CBFF”), undivided interests in producing oil and natural gas properties in which Moriah Properties, Ltd. also owns an interest. CSFI owns working interests burdened by net profits interests owned by MFI and CBFF. CSFI has contracted with MRI to provide certain accounting and management services related to the ownership of these oil and gas interests.
(8) Commitments and Contingencies
      From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, Legacy is not currently a party to any proceeding that it believes, if determined in a manner adverse to Legacy, could have a potential material adverse effect on its financial condition, results of operations or cash flows. Legacy believes the likelihood of such a future event to be remote.
      Additionally, Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected.
(9) Business and Credit Concentrations
Cash
      Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash.
Revenue and Trade Receivables
      Substantially all Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2003, 2004, or 2005. Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is tabulated in Note 12.
(10) Oil and Natural Gas Swaps
      Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the price of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes.
      All of these price risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. These derivative instruments are intended to hedge our price-risk and may be considered hedges for economic purposes but Legacy has chosen not to designate them as cash flow hedges. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings.
      By using derivative instruments to hedge exposures to changes in commodity prices, Legacy exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes Legacy, which creates repayment risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.
      For the years ended December 31, 2003, 2004, and 2005 and the nine months ended September 30, 2005 and 2006, Legacy included in revenue realized and unrealized losses related to its oil and natural gas derivatives. The impact on total revenue from hedging activities was as follows:
                                         
    Year Ended December 31,   Nine Months Ended September 30,
         
    2003   2004   2005   2005   2006
                     
Crude oil derivative contract settlements
   $ (444,281 )   $ 46,020     $ (3,530,651 )   $ (3,530,651 )   $ (6,897,833 )
Natural gas derivative contract settlements
     (178,770 )     (119,850 )     —       —       4,715,768  
Unrealized change in fair value — oil
     450,279       (678,803 )     (910,738 )     (2,855,764 )     1,342,276  
Unrealized change in fair value — gas
     (110,100 )     119,850       (1,717,476 )     (1,263,029 )     6,373,342  
                               
    $ (282,872 )   $ (632,783 )   $ (6,158,865 )   $ (7,649,444 )   $ 5,533,553  
                               
      In its statement of cash flows for the nine months ended September 30, 2005, Legacy classified $3,530,651 paid to settle crude oil derivative contracts as cash used in operating activities. In the accompanying statements of cash flows, the classification of such payments has been revised and they are classified as cash used in investing activities for the year ended December 31, 2005 and the nine months ended September 30, 2005 and 2006.
      On May 25, July 5, August 1, 2005 and January 13 and January 17, 2006, Legacy entered into NYMEX West Texas Intermediate crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:
                     
    Annual    
Calendar   Volume   Price
Year   (Bbls)   ($/Bbls)
         
  2006       275,268     $ 60.39  
  2007       209,066     $ 60.00  
  2008       195,579     $ 60.50  
  2009       203,915     $ 63.22  
  2010       192,366     $ 61.90  

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
      On September 29 and December 2, 2005 and January 13, 2006 Legacy entered into the NYMEX Henry Hub natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:
                     
    Annual    
Calendar   Volume   Price
Year   (MMBtu)   ($/MMBtu)
         
  2006       620,610     $ 11.80  
  2007       562,609     $ 9.88  
  2008       518,797     $ 8.79  
  2009       486,131     $ 8.73  
  2010       454,733     $ 8.34  
      On September 14, 2005 and January 17, 2006, MBN Properties LP entered into the following NYMEX WTI oil swaps and NYMEX natural gas swaps paying floating prices and receiving fixed prices for a portion of its future oil and natural gas production as indicated below:
                                     
    Oil Swaps   Natural Gas Swaps
         
    Annual       Annual    
Calendar   Volume   Price   Volume   Price
Year   (Bbls)   ($/Bbl)   (MMBtu)   ($/MMBtu)
                 
  2006       179,224     $ 66.63       660,925     $ 10.28  
  2007       133,385     $ 64.15       588,498     $ 9.02  
  2008       117,634     $ 62.25       529,386     $ 8.30  
  2009       105,464     $ 61.05       478,314     $ 7.77  
  2010       95,267     $ 60.15       434,879     $ 7.37  
      The purpose of the hedging program was to reduce the volatility of oil and natural gas prices and its impact on the predictability of the Moriah Group’s cash flows in light of its entering into an expanded credit facility on September 13, 2005, as noted above. The MBN swaps were put in place to hedge the oil and natural gas price risk associated with the PITCO acquisition on September 14, 2005.
      In September 2006, we paid our counterparty $4 million to cancel and reset oil swaps for 372,000 barrels in 2007 from $60.00 to $65.82 per barrel and for 348,000 barrels in 2008 from $60.50 to $66.44 per barrel.
      As of September 30, 2006, Legacy had the following NYMEX West Texas Intermediate crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:
                             
    Annual        
Calendar   Volumes   Average   Price
Year   (Bbls)   Price per Bbl   Range per Bbl
             
  2006       169,981     $ 62.17       $59.38 - $68.00  
  2007       671,637     $ 67.62       $64.15 - $75.70  
  2008       618,689     $ 67.11       $62.25 - $73.45  
  2009       571,453     $ 64.46       $61.05 - $71.40  
  2010       426,687     $ 61.51       $60.15 - $61.90  

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
      As of September 30, 2006, Legacy had the following NYMEX Henry Hub natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:
                             
    Annual        
Calendar   Volumes   Average   Price
Year   (Mcf)   Price per Mcf   Range per Mcf
             
  2006       428,827     $ 10.68       $9.49 - $11.56  
  2007       1,558,504     $ 9.56       $9.02 - $11.83  
  2008       1,422,732     $ 8.61       $7.98 - $10.58  
  2009       1,316,354     $ 8.38       $7.77 - $10.18  
  2010       1,218,899     $ 7.99       $7.37 - $ 9.73  
      As of September 30, 2006, Legacy had the following gas basis swaps in which we receive floating NYMEX prices less a fixed basis differential and pay prices on the floating Waha index, a natural gas hub in West Texas. The prices that we receive for our natural gas sales follow Waha more closely than NYMEX:
                     
    Annual    
Calendar   Volumes   Price
Year   (Mcf)   Range per Mcf
         
  2006       429,000       $(0.99) - $(1.15)  
  2007       1,560,000       $        (0.88)  
  2008       1,422,000       $        (0.84)  
  2009       1,320,000       $        (0.68)  
  2010       1,200,000       $        (0.57)  
(11) Discontinued Operations
      During 2003 and 2004, Legacy disposed of certain producing oil and natural properties which meet the guidelines for treatment as discontinued operations under FAS 144. The following table sets for the operating results for the discontinued operations:
                   
    Year Ended
    December 31,
     
    2003   2004
         
Oil sales
   $ 62,072     $ 24,625  
Natural gas sales
     796       51  
Oil and natural gas production expenses
     (46,725 )     (8,553 )
Production and other taxes
     (2,938 )     (1,142 )
Depreciation, depletion and amortization
     (2,971 )     —  
             
 
Income (loss) from discontinued operations
     10,234       14,981  
             
 
Gain on disposal
     233,073       7,165  
             
Total income from discontinued operations
   $ 243,307     $ 22,146  
             

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
(12) Sales to Major Customers
      Legacy operates as one business segment within the Permian Basin region. It sold crude oil and natural gas production representing 10% or more of total revenues for the years ended December 31, 2003, 2004 and 2005 as shown below:
                         
    2003   2004   2005
             
ConocoPhillips
     12%       9%       10%  
Navajo Crude Oil Marketing
     15%       17%       16%  
Plains Marketing, LP
     16%       20%       18%  
      In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of the Legacy’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. We believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.
(13) Asset Retirement Obligation
      In June 2001, the FASB issued FAS No. 143, which requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at Legacy’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
      Legacy adopted FAS No. 143 on January 1, 2003, which resulted in a net increase to oil and natural gas properties of $1.9 million and related liabilities of $2.1 million. These amounts reflect the ARO of Legacy had the provisions of FAS No. 143 been applied since inception and resulted in a non-cash charge to earnings of $223,377. Going forward Legacy will record an abandonment liability associated with its oil and natural gas wells when those assets are placed in service.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
      The following table reflects the changes in the ARO during the years ended December 31, 2003, 2004 and 2005 and the nine months ended September 30, 2005 and 2006.
                                         
    December 31,   September 30,
         
    2003   2004   2005   2005   2006
                     
Asset retirement obligation — beginning of period
   $ 2,144,259     $ 2,112,687     $ 1,952,866     $ 1,952,866     $ 2,302,147  
Liabilities incurred in Legacy Formation
     —       —       —       —       1,467,241  
Liabilities incurred during the period
     330,391       5,164       446,901       445,169       1,877,520  
Liabilities associated with properties sold
     (95,027 )     (20,885 )     —       —       —  
Liabilities associated with properties distributed to owners
     (191,110 )     —       —       —       —  
Liabilities settled during the period
     —       —       (53,852 )     (40,655 )     (111,810 )
Current period accretion
     78,953       88,053       109,429       84,881       157,539  
Current period revisions to accretion expense
     (108,310 )     (185,188 )     (163,281 )     (119,823 )     —  
Current period revisions to oil and natural gas properties
     (46,469 )     (46,965 )     10,084       (275,117 )     —  
                               
Asset retirement obligation — end of period
   $ 2,112,687     $ 1,952,866     $ 2,302,147     $ 2,047,321     $ 5,692,637  
                               
      The discount rate used in calculating the ARO was 4.0% in 2003, 4.1% in 2004 and 6.0% at December 31, 2005. These rates approximate Legacy’s borrowing rates.
(14) Earnings Per Unit
      The following table sets forth the computation of basic and diluted net earnings per unit (in thousands, except per unit):
                                           
        Nine Months Ended
    Year Ended December 31,   September 30,
         
    2003   2004   2005   2005   2006
                     
Numerator:
                                        
 
Earnings from continuing operations applicable to unitholders and partners
   $ 4,207     $ 9,194     $ 5,859     $ 1,285     $ 6,669  
                               
Denominator:
                                        
 
Denominator for basic and diluted earnings per unit
     9,489       9,489       9,489       9,489       15,953  
                               
Basic and diluted earnings per unit
   $ 0.44     $ 0.97     $ 0.62     $ 0.14     $ 0.42  
                               
(15) Unit-Based Compensation
      On March 15, 2006, Legacy issued 52,616 units of restricted unit awards to two employees. The restricted units awarded vest ratably over a three-year period, beginning on the date of grant. On May 5, 2006, Legacy issued 12,500 units of restricted unit awards to an employee. The restricted units awarded vest ratably over a five-year period, beginning on the date of grant. Compensation expense related to restricted units was $191,959 for the nine months ended September 30, 2006. As of September 30, 2006, there was a total of $915,013 of unrecognized compensation costs related to the non-vested portion of these restricted units. At September 30, 2006, this cost was expected to be recognized over a weighted-average period of 2.9 years.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
      On July 17, 2006, Legacy issued 190,000 unit option awards to officers and employees which vest ratably on March 15, 2007, 2008 and 2009. On July 17, 2006, Legacy issued 11,000 unit option awards to an employee which vest ratably on May 1, 2007, 2008 and 2009. On July 17, 2006, Legacy issued 40,000 unit option awards to an employee which vest ratably on May 5, 2007, 2008 and 2009. On July 17, 2006, Legacy issued 10,000 unit option awards to an employee which vest ratably on June 30, 2007, 2008 and 2009. On September 15, 2006, Legacy issued 10,000 unit option awards to an employee which vest ratably on August 17, 2007, 2008 and 2009. All options granted expire five years from the grant date. All options granted in the three month period ended September 30, 2006, have an exercise price of $17.00 per unit. All options granted are exercisable when they vest.
      For the nine months ended September 30, 2006, Legacy recorded $116,850 of compensation expense based on its use of the Black Scholes model to estimate the grant-date fair value of these unit option awards. Compensation expense is based upon amortization of the grant-date fair value over the vesting period of the underlying unit option. For the purpose of determining compensation expense, Legacy treats each award of units options with graded vesting as separate awards (e.g., step vesting one third each year over a three-year period) which results in accelerated expense recognition. Since Legacy is a non-public company and has no trading history, it has used an estimated volatility factor of approximately 37% based upon a representative group of publicly-traded companies in the energy industry and employed the fair value method to estimate the grant-date fair value to be amortized over the vesting periods of the unit options awarded. In the absence of historical data, Legacy has assumed an estimated forfeiture rate of 5%. Legacy has assumed an annual distribution rate of $1.64 per unit. Legacy has used a weighted-average risk free interest rate of 4.87% in its Black Scholes calculation of grant-date fair value. As of September 30, 2006, the average grant-date fair value was $2.43 per unit. Legacy has 40,000 unit options authorized for future grants.
(16) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities
      Costs incurred by Legacy in oil and natural gas property acquisition and development are presented below:
                           
    Year Ended December 31,
     
    2003   2004   2005
             
Development costs
   $ 103,462     $ 1,636,989     $ 1,958,455  
Exploration costs
     1,464,607       822       —  
Acquisition costs:
                        
 
Proved properties
     4,625,642       1,645,539       65,405,917  
 
Unproved properties
     —       —       2,928  
                   
 
Total
   $ 6,193,711     $ 3,283,350     $ 67,367,300  
                   
Moriah Group’s share of costs incurred by equity method investee
   $ 624,487     $ —     $ —  
                   
      Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas.

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
(17) Oil and Natural Gas Capitalized Costs
      Aggregate capitalized costs for Legacy related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization are presented below:
                   
    December 31,
     
    2004   2005
         
Proved oil and natural gas properties
   $ 18,270,228     $ 85,363,482  
Unproved properties
     —       2,928  
             
 
Total oil and natural gas properties
     18,270,228       85,366,410  
Accumulated depletion, depreciation and amortization
     (6,046,262 )     (8,194,385 )
             
    $ 12,223,966     $ 77,172,025  
             
(18) Net Proved Oil and Natural Gas Reserves (Unaudited)
      The proved oil and natural gas reserves of Legacy have been estimated by an independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., as of December 31, 2003, 2004 and 2005. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules based on year-end prices and costs. The table below includes the reserves associated with the PITCO acquisition in September, 2005, which is reflected in the December 31, 2005 balances. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, is shown below:
                     
    Oil and   Natural
    Condensate   Gas
    (MBbls)   (MMcf)
         
Total Proved Reserves
                
 
Balance, December 31, 2002
     2,946       10,891  
   
Purchase of minerals-in-place
     416       232  
   
Sales of minerals-in-place
     (330 )     (1,088 )
   
Extensions and discoveries
     5       66  
   
Revisions of previous estimates
     574       1,021  
   
Production
     (281 )     (848 )
             
 
Balance, December 31, 2003
     3,330       10,274  
   
Purchase of minerals-in-place
     228       256  
   
Sale of minerals-in-place
     (5 )     (2 )
   
Extensions and discoveries
     120       467  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     86       33  
   
Revisions of previous estimates due to prices and performance
     637       225  
   
Production
     (287 )     (783 )
             

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
                     
    Oil and   Natural
    Condensate   Gas
    (MBbls)   (MMcf)
         
 
Balance, December 31, 2004
     4,109       10,470  
   
Purchase of minerals-in-place
     3,541       12,800  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     794       1,258  
   
Revisions of previous estimates due to prices and performance
     28       956  
   
Production
     (354 )     (1,027 )
             
 
Balance, December 31, 2005
     8,118       24,457  
             
Proved Developed Reserves
                
 
December 31, 2002
     2,946       10,891  
 
December 31, 2003
     3,330       10,274  
 
December 31, 2004
     4,109       10,470  
 
December 31, 2005
     6,380       20,618  
Legacy’s share of Proved Reserves of Equity Method Investee
                
 
December 31, 2003
     189       1,146  
 
December 31, 2004
     —       —  
 
December 31, 2005
     —       —  
(19) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves (Unaudited)
      Summarized in the following table is information for Legacy inclusive of MBN/PITCO from September 2005 with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future cash inflows are computed by applying year-end prices relating to the Legacy’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration, and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because Legacy is a nontaxable entity.
                           
    December 31,
     
    2003   2004   2005
             
    (Thousands)
Future production revenues
   $ 152,604     $ 220,989     $ 684,021  
Future costs:
                        
 
Production
     (68,729 )     (95,780 )     (242,796 )
 
Development
     —       (178 )     (27,609 )
                   
Future net cash flows before income taxes
     83,875       125,031       413,616  
10% annual discount for estimated timing of cash flows
     (42,490 )     (64,674 )     (221,619 )
                   
Standardized measure of discounted net cash flows
   $ 41,385     $ 60,357     $ 191,997  
                   
Legacy’s share of standardized measure of discounted future net cash flows of equity method investee
   $ 2,955     $ —     $ —  
                   

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LEGACY RESERVES LP (FORMERLY MORIAH GROUP)
NOTES TO FINANCIAL STATEMENTS — (Continued)
      The Standardized Measure is based on the following oil and natural gas prices realized over the life of the properties at the wellhead as of the following dates:
                         
    December 31,
     
    2003   2004   2005
             
Oil (per Bbl)
   $ 29.40     $ 40.55     $ 57.64  
Natural gas (per MMBtu)
   $ 5.32     $ 5.19     $ 8.82  
      The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows which reflects the PITCO acquisition in 2005:
                             
    Year Ended December 31,
     
    2003   2004   2005
             
    (Thousands)
Increase (decrease):
                        
 
Sales, net of production costs
   $ (7,472 )   $ (9,685 )   $ (17,532 )
 
Net change in sales prices, net of production costs
     3,781       10,605       36,574  
 
Changes in estimated future development costs
     —       (86 )     (21,401 )
 
Extensions and discoveries, net of future production and development costs
     157       2,370       —  
 
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     —       836       19,319  
 
Revisions of previous estimates due to prices and performance
     6,115       6,959       3,156  
 
Previously estimated development costs incurred
     —       —       (178 )
 
Purchase of minerals-in place
     3,294       3,236       102,289  
 
Sales of minerals in place
     (4,194 )     (36 )     —  
 
Other
     1,514       1,287       4,458  
 
Accretion of discount
     3,340       3,486       4,955  
                   
   
Net increase
     6,535       18,972       131,640  
Standardized measure of discounted future net cash flows:
                        
 
Beginning of year
     34,850       41,385       60,357  
                   
 
End of year
   $ 41,385     $ 60,357     $ 191,997  
                   
      The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.
(20) Subsequent Events
      On October 27, 2006 the board of directors of Legacy’s general partner declared a $0.41 per unit cash distribution to all unitholders of record on October 31, 2006.
      On October 10, 2006, Legacy granted 12,000 unit options to two new employees. These options were granted under the Legacy Reserves LP Long-Term Incentive Plan, have a strike price of $17.25 per unit and vest one-third each year over a three year period.
      On November 10, 2006, Legacy filed an initial IPO registration statement with the SEC with which it plans to issue 6,000,000 units for estimated net proceeds of $104,250,000.

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Report of Independent Registered Public Accounting Firm
To the Members of
Legacy Reserves GP, LLC
      We have audited the accompanying balance sheet of Legacy Reserves GP, LLC as of December 31, 2005. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.
      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis of 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 balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for your opinion.
      In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Legacy Reserves GP, LLC as of December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
  /s/ BDO Seidman, LLP
Houston, Texas
May 5, 2006

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LEGACY RESERVES GP, LLC
BALANCE SHEET
As of December 31, 2005
         
Assets
        
Total assets
   $ —  
       
 
Member’s equity
        
Member’s equity
   $ 1,000  
       
Receivable from member
     (1,000 )
       
Total equity
   $ —  
       
See accompanying note to balance sheet.

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LEGACY RESERVES GP, LLC
NOTE TO BALANCE SHEET
As of December 31, 2005
      Legacy Reserves GP, LLC, a Delaware limited liability company (the “General Partner”) was formed on October 26, 2005 to become the general partner of Legacy Reserves LP (the “Partnership”), a Delaware limited partnership. MBN Properties LP will invest $1,000 and owns 100% of the membership interest in the General Partner. The General Partner will invest $1 in the Partnership and owns a 0.1% general partner interest in the Partnership.

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Report of Independent Registered Public Accounting Firm
Brothers Group
Midland, Texas
      We have audited the accompanying combined balance sheets of the Brothers Group, as defined in Note 1(a), as of and for the years ended December 31, 2004 and 2005 and the related combined statements of operations, owners’ equity, and cash flows for each of the years in the three year period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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 combined financial statements referred to above present fairly, in all material respects, the financial position of the Brothers Group at December 31, 2004 and 2005 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
      As discussed in Note 12 to the combined financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.
  /s/ BDO Seidman, LLP
Houston, Texas
May 5, 2006

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BROTHERS GROUP
COMBINED BALANCE SHEETS
                     
    December 31,
     
    2004   2005
         
ASSETS
                
Current assets:
                
 
Cash and cash equivalents
   $ 2,069,685     $ 4,294,126  
 
Accounts receivable, net:
                
   
Oil and natural gas
     1,642,621       1,481,111  
   
Joint interest owners
     1,601,182       1,128,956  
 
Notes receivable (Note 3)
     2,230,000       —  
 
Prepaid expenses and other current assets
     86,329       106,282  
             
   
Total current assets
     7,629,817       7,010,475  
             
Proved oil and natural gas properties, at cost, using the successful efforts method of accounting
     18,699,991       20,001,062  
Accumulated depletion, depreciation and amortization
     (6,984,578 )     (7,583,307 )
             
      11,715,413       12,417,755  
             
Office furniture and equipment, net
     75,064       111,745  
Notes receivable (Note 3)
     1,000,000       —  
Notes receivable — affiliated entity (Note 6)
     —       13,708,920  
Other assets, net
     13,458       208,197  
             
    $ 20,433,752     $ 33,457,092  
             
 
LIABILITIES AND OWNERS’ EQUITY
                
Current liabilities:
                
 
Current portion of notes payable (Note 4)
   $ 2,000,000     $ —  
 
Accounts payable
     521,156       1,099,918  
 
Accrued oil and natural gas liabilities
     2,930,931       2,718,745  
 
Fair value of oil and natural gas swaps (Note 10)
     —       149,956  
 
Asset retirement obligation (Note 12)
     54,815       126,528  
 
Other
     —       172,188  
             
   
Total current liabilities
     5,506,902       4,267,335  
Long-term debt (Note 4)
     —       15,402,000  
Fair value of oil and natural gas swaps (Note 10)
     —       1,231,201  
Asset retirement obligation (Note 12)
     1,498,701       1,352,841  
             
Total liabilities
     7,005,603       22,253,377  
             
 
Commitments and contingencies (Note 8)
                
Owners’ equity
     13,428,149       11,203,715  
             
    $ 20,433,752     $ 33,457,092  
             
See accompanying notes to combined financial statements.

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BROTHERS GROUP
COMBINED STATEMENTS OF OPERATIONS
                             
    Year Ended December 31,
     
    2003   2004   2005
             
Revenues:
                        
 
Oil sales
   $ 6,321,095     $ 9,665,774     $ 12,124,874  
 
Natural gas sales
     2,276,771       2,975,229       3,783,771  
 
Realized and unrealized loss on oil and natural gas swaps (Note 10)
     (192,580 )     46,576       (4,855,124 )
                   
   
Total revenues
     8,405,286       12,687,579       11,053,521  
                   
Expenses:
                        
 
Oil and natural gas production
     2,314,883       2,352,679       3,142,361  
 
Production and other taxes
     471,862       722,168       965,078  
 
General and administrative
     978,327       1,032,848       1,187,145  
 
Dry hole costs
     812,436       345,143       204,968  
 
Depletion, depreciation, amortization and accretion
     829,051       967,415       826,800  
 
Impairment of long-lived assets
     226,986       —       —  
 
(Gain) loss on sale of assets
     10,365       (244,164 )     10,723  
                   
   
Total expenses
     5,643,910       5,176,089       6,337,075  
                   
   
Operating income
     2,761,376       7,511,490       4,716,446  
                   
Other income (expense):
                        
 
Interest income
     1,030       82,637       844,603  
 
Interest expense (Note 4)
     (163,158 )     (118,818 )     (396,676 )
 
Gain on sale of partnership investment
     —       1,335,277       —  
 
Equity in income (loss) of partnerships (Note 6)
     314,510       185,327       (1,232,713 )
 
Other
     7,406       29,425       95,601  
                   
   
Income before cumulative effect of change in accounting principle
     2,921,164       9,025,338       4,027,261  
Cumulative effect of accounting change (Note 12)
     (231,542 )     —       —  
                   
   
Net income
   $ 2,689,622     $ 9,025,338     $ 4,027,261  
                   
See accompanying notes to combined financial statements.

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BROTHERS GROUP
COMBINED STATEMENTS OF OWNERS’ EQUITY
                                                 
    Common   Retained   Stockholders’   Partners’   Owner’s   Total Owners’
    Stock   Earnings   Equity   Capital   Equity   Equity
                         
Balance, January 1, 2003
   $ 2,000     $ 991,036     $ 993,036     $ 3,849,069     $ 738,518     $ 5,580,623  
Capital contributions
     —       —       —       —       49,691       49,691  
Distributions to owners
     —       (180,883 )     (180,883 )     (745,321 )     (943,816 )     (1,870,020 )
Net income
     —       81,651       81,651       1,800,490       807,481       2,689,622  
                                     
Balance, December 31, 2003
     2,000       891,804       893,804       4,904,238       651,874       6,449,916  
Capital contributions
     —       8,258       8,258       —       106,672       114,930  
Distributions to owners
     —       —       —       (743,020 )     (1,419,015 )     (2,162,035 )
Net income (loss)
     —       (93,545 )     (93,545 )     7,612,453       1,506,430       9,025,338  
                                     
Balance, December 31, 2004
     2,000       806,517       808,517       11,773,671       845,961       13,428,149  
Capital contributions
     —       —       —       —       195,471       195,471  
Deemed capital contribution
     —       —       —       110,699       —       110,699  
Distributions to owners
     —       (484,397 )     (484,397 )     (4,423,401 )     (1,650,067 )     (6,557,865 )
Net income (loss)
     —       (49,480 )     (49,480 )     3,023,020       1,053,721       4,027,261  
                                     
Balance, December 31, 2005
   $ 2,000     $ 272,640     $ 274,640     $ 10,483,989     $ 445,086     $ 11,203,715  
                                     
See accompanying notes to combined financial statements.

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BROTHERS GROUP
COMBINED STATEMENTS OF CASH FLOWS
                               
    Year Ended December 31,
     
    2003   2004   2005
             
Cash flows from operating activities:
                        
 
Net income
   $ 2,689,622     $ 9,025,338     $ 4,027,261  
   
Adjustment to reconcile net income to net cash provided by operating activities:
                        
   
Dry hole costs
     812,436       345,143       204,968  
   
Depletion, depreciation, amortization and accretion
     829,051       967,415       826,800  
   
Impairment of long-lived assets
     226,986       —       —  
   
(Gain) loss on oil and natural gas swaps
     (241,944 )     (79,900 )     4,855,124  
   
(Gain) loss on sale of assets
     10,365       (1,579,441 )     10,723  
   
Equity in (income) loss of partnerships
     (314,510 )     (185,327 )     1,232,713  
   
Accrued interest income — related party
     —       —       (446,353 )
   
Accrued interest expense
     —       —       172,188  
   
Distributions from oil and natural gas partnership
     140,000       105,000       —  
   
Non-cash effect of accounting change
     231,542       —       —  
 
Changes in assets and liabilities:
                        
   
(Increase) decrease in accounts receivable, oil and natural gas
     655,926       (965,342 )     161,510  
   
(Increase) decrease in accounts receivable, joint interest owners
     355,916       (641,761 )     472,226  
   
(Increase) decrease in other assets
     12,948       (19,960 )     (2,193 )
   
Increase (decrease) in accounts payable
     (580,406 )     358,769       578,762  
   
Increase (decrease) in accrued oil and natural gas liabilities
     (66,497 )     843,538       (212,186 )
                   
     
Total adjustments
     2,071,813       (851,866 )     7,854,282  
                   
     
Net cash provided by operating activities
     4,761,435       8,173,472       11,881,543  
                   
Cash flows from investing activities:
                        
 
Investment in oil and natural gas properties
     (2,863,136 )     (2,897,017 )     (1,796,867 )
 
Proceeds from sale of assets
     452,159       2,344,094       —  
 
Investment in other property, plant and equipment
     (51,170 )     (29,995 )     (58,793 )
 
Investment in notes receivable
     (3,650,000 )     (2,230,000 )     (14,384,581 )
 
Collection of notes receivable
     —       2,650,000       3,230,000  
 
Cash settlements on oil and natural gas swaps
     —       —       (3,473,967 )
                   
     
Net cash used in investing activities
     (6,112,147 )     (162,918 )     (16,484,208 )
                   
Cash flows from financing activities:
                        
 
Proceeds from notes payable
     5,572,318       2,200,000       24,952,000  
 
Payments of notes payable
     (2,484,606 )     (6,672,317 )     (11,550,000 )
 
Payment of debt issuance costs
     —       —       (212,500 )
 
Capital contributed by owners
     49,691       114,930       195,471  
 
Distributions of capital
     (1,870,020 )     (2,162,035 )     (6,557,865 )
                   
     
Net cash provided by (used in) financing activities
     1,267,383       (6,519,422 )     6,827,106  
                   
     
Net increase (decrease) in cash and cash equivalents
     (83,329 )     1,491,132       2,224,441  
Cash and cash equivalents, beginning of period
     661,882       578,553       2,069,685  
                   
Cash and cash equivalents, end of period
   $ 578,553     $ 2,069,685     $ 4,294,126  
                   
Non-Cash Investing and Financing Activities:
                        
 
Asset retirement obligations costs and liabilities
   $ 262,511     $ (61,400 )   $ (297 )
                   
 
Deemed capital contribution
   $ —     $ —     $ 110,699  
                   
See accompanying notes to combined financial statements.

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS
(1)  Summary of Significant Accounting Policies
  (a)  Basis of Presentation
      The accompanying combined financial statements include the accounts of Brothers Production Company, Inc. (“BPCI”), Brothers Operating Company, Inc. (“BOCI”), Brothers Production Properties, Ltd. (“BPPL”), and the oil and natural gas interests individually owned by Wanda McGraw through her ownership of J&W McGraw Properties, Ltd. and the Jack R. McGraw Family Trust. The accounts are presented on a combined basis because these entities are under common control. The partners, shareholders and owners of these entities have other investments, such as real estate, that are held either individually or through other legal entities that are not presented as part of these financial statements. The financial statements presented herein only involve activities related to oil and natural gas properties. All significant intercompany accounts and transactions have been eliminated. The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. As used herein, the term Brothers Group refers to all of these entities on a combined basis unless the context specifies otherwise. Effective October 1, 2005, Wanda McGraw assigned the selected oil and natural gas properties included in these consolidated financial statements to J&W McGraw Properties, Ltd., a Texas limited partnership whose general partner is Wanda J. McGraw Management, LLC. The limited partners of J&W McGraw Properties, Ltd. are Wanda McGraw (50.0%) the Jack R. McGraw Marital Trust (29.57%) and the Jack R. McGraw Family Trust (20.43%). The beneficiaries of the Jack R. McGraw Family Trust are all members of the McGraw family. The general partner holds a 1% general partner interest and is a Texas limited liability company owned by Wanda McGraw.
  (b)  Organization and Description of Business
      The Brothers Group owns and operates oil and natural gas producing properties located primarily in the Permian Basin of West Texas and southeast New Mexico. The Brothers Group has acquired oil and natural gas producing properties and drilled leasehold. The Brothers Group is comprised of BPPL, BPCI, BOCI, and Wanda McGraw. BPCI was organized as a sub-chapter S corporation on May 1, 1990 under the laws of the State of Texas. BOCI was organized as a sub-chapter S corporation on November 15, 1995 under the laws of the State of Texas, and serves as the general partner to BPPL and owns 1.0% of that entity. BPPL was organized as a limited partnership on October 21, 1999 under the laws of the State of Texas. Wanda J. McGraw, an individual, together with her late husband, Jack R. McGraw, has owned oil and natural gas working interests since April, 1981. Timothy McGraw, Scott McGraw, Kyle McGraw and Travis McGraw, (the “McGraw brothers”) are all sons of Wanda McGraw and are the sole owners of BPCI, BPPL and BOCI with each brother owning a 25% interest in each entity. Thus, the selected oil and gas activities of Wanda J. McGraw are combined with the financial statements of BPCI, BPPL and BOCI.
  (c)  Cash Equivalents
      For purposes of the combined statement of cash flows, the Brothers Group considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents.
  (d)  Trade Accounts Receivable
      Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Brothers Group routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review after all means of collection have been exhausted and the potential recovery is considered remote. The Brothers Group does not have any off-balance-sheet credit exposure related to its customers (see Note 11).

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
  (e)  Oil and Natural Gas Properties
      The Brothers Group accounts for oil and natural gas properties by the successful efforts method. Under this method of accounting, costs relating to the acquisition of and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities.
      Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. FAS No. 19 requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped, and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by the Brothers Group’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., and are subject to future revisions based on availability of additional information. The Brothers Group’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 12, the Brothers Group follows FAS No. 143. Under FAS No. 143, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by the Brothers Group’s engineers using existing regulatory requirements and anticipated future inflation rates.
      Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation.
      Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. The Brothers Group assesses impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using oil and natural gas prices as of the last day of the statement period held constant. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2004 and 2005, the estimated undiscounted future cash flows for the Brothers Group’s proved oil and natural gas properties exceeded the net capitalized costs, and no impairment was required to be recognized. In 2003, impairment of $226,986 was recognized when a dry hole was drilled on the Mountain Cat Prospect and the remainder of the unproved acreage was written off. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Costs related to unproved mineral interests that are individually insignificant are amortized over the shorter of the exploratory period or the lease/concession holding period which is typically three years in the Permian Basin.
  (f)  Oil and Natural Gas Reserve Quantities
      The Brothers Group’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche Petroleum Consultants, Ltd. prepares a reserve and economic evaluation of all the Brothers Group’s properties on a well-by-well

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
basis utilizing information provided to it by the Brothers Group and utilizing information available from state agencies that collect information reported to it by the operators of the Brothers Group’s properties.
      Reserves and their relation to estimated future net cash flows impact the Brothers Group’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Brothers Group prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of the Brothers Group’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
      The Brothers Group’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.
  (g)  Income Taxes
      No provision for income taxes is made in the Brothers Group’s consolidated financial statements because the taxable income or loss of the Brothers Group is included in the income tax returns of the individual owners.
  (h)  Derivative Instruments and Hedging Activities
      The Brothers Group periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. The Brothers Group accounts for these activities pursuant to FAS No. 133 — Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.
      The Brothers Group does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices. Therefore, the mark to market of these instruments is recorded in current earnings (see Note 10).
  (i)  Use of Estimates
      Management of the Brothers Group has made a number of estimates and assumptions relating to the reporting of assets, liabilities and revenues and expenses, and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, future cash flows from oil and natural gas properties, depreciation, depletion and amortization and asset retirement obligations.
  (j)  Revenue Recognition
      Sales of crude oil and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location.

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
      Virtually all of the Brothers Group’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. As a result, the Brothers Group’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. The Brothers Group believes that the pricing provisions of its oil and natural gas contracts are customary in the industry.
      We currently use the “net-back” method of accounting for transportation arrangements of our natural gas sales. We sell natural gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by our purchasers and reflected in the wellhead price. Our contracts with respect to the sale of our natural gas produced, with one immaterial exception, provide us with a net price payment. That is, when we are paid for our natural gas by our purchasers, we receive a price which is net of any costs incurred for treating, transportation, compression, etc. In accordance with the terms of our contracts, the payment statements we receive from our purchasers show a single net price without any detail as to treating, transportation, compression, etc. Thus, our revenues are recorded at this single net price.
      Natural gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant natural gas imbalance positions as of December 31, 2003, 2004 or 2005.
      We are paid a monthly operating fee for each well we operate for outside owners. The fee covers monthly general and administrative costs. As the operating fee is a reimbursement of costs incurred on behalf of third parties, the fee has been netted against general and administrative expense.
  (k)  Investments
      Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where the Brother’s Group exercises significant influence, but not a controlling interest, are accounted for by the equity method. Under the equity method, our investments are stated at cost plus the equity in undistributed earnings and losses after acquisition.
  (l)  Office Furniture and Equipment
      Office furniture and equipment other than oil and natural gas properties is carried at cost. Depreciation is provided principally on the straight-line method over useful lives as follows:
     
Furniture and equipment
   5-7 years
Vehicles
   5 years
      Maintenance and repairs are charged to expense as incurred. Major renewals and betterments are capitalized. Upon the sale or other disposition of assets, the cost and related accumulated depreciation, are removed from the accounts, the proceeds applied thereto, and any resulting gain or loss is reflected in net income for the period.
  (m)  Environmental
      The Brothers Group is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Brothers Group 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

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments are fixed and readily determinable.
  (n)  Recently Issued Accounting pronouncements
      Emerging Issues Task Force (“EITF”) Issue 04-9 and Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) FAS 19-1: Statement of Financial Accounting Standards (“FAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” requires the cost of drilling an exploratory well to be capitalized pending determination of whether the well has found proved reserves. If this determination cannot be made at the conclusion of drilling, FAS No. 19 sets out additional requirements for continuing to carry the cost of the well as an asset. These requirements include firm plans for further drilling and a one-year time limitation on continued capitalization in certain instances. In April 2005, the FASB issued FSP FAS 19-1, which was adopted effective January 1, 2005. This FSP amends FAS No. 19 to allow continued capitalization when (a) the well has found a sufficient quantity of reserves to justify proceeding with the project plan and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project which may include more than one exploratory well if the reserves are intended to be extracted in a single integrated operation. The FSP also requires increased disclosures. Adoption of this rule did not have a material impact on our consolidated earnings in 2005. If this FSP had been applied to 2004, it would not have had a material effect on our earnings for that year.
      FAS No. 153: In 2004, the FASB issued FAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29,” which became effective July 1, 2005. With certain exceptions, this requires exchanges of nonmonetary assets to be recorded at fair value. Previously, these transactions were generally recorded at book value. This pronouncement results in reporting in earnings, gains and losses on exchanges of nonmonetary assets. Adoption of this rule did not have a material impact on either our earnings or consolidated balance sheet in 2005.
      FAS No. 154: In 2005, the FASB issued FAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FAS No. 3,” which is effective January 1, 2006. Opinion 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This Statement requires retrospective application (restatement) to prior periods’ financial statements of changes in accounting principle. This Statement also applies to changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.
      FAS Interpretation No. 47: In March 2005, the FASB issued FAS Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FAS Statement No. 143,” “Accounting for Asset Retirement Obligations,” which is effective no later than December 31, 2005. This pronouncement clarifies that the term “conditional asset retirement obligation” as used in FAS Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. This interpretation is not expected to have a material impact on either our earnings or consolidated balance sheet.

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
(2)  Fair Values of Financial Instruments
      The estimated fair values of the Brothers Group’s financial instruments closely approximate the carrying amounts as discussed below:
        Cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.
 
        Notes receivable. The carrying amounts approximate fair value due to the comparability of the interest rate to market interest rates for instruments of similar terms and credit quality.
 
        Debt. The carrying amount of the revolving long-term debt approximates fair value because the Brothers Group’s current borrowing rate does not materially differ from market rates for similar bank borrowings.
 
        Commodity price derivatives. The fair market values of commodity derivative instruments are estimated based upon the current market price of the respective commodities at the date of valuation. It represents the amount, which the Brothers Group would be required to pay or able to receive, based upon the differential between a fixed and a variable commodity price as specified in the hedge contracts.
(3)  Notes Receivable
      In addition to the subordinated notes receivable from MBN Properties LP and MBN Management LLC (see Note 6), the Brothers Group has two outstanding notes receivable. The first note is from a company that operates oil and natural gas properties in East Texas. The second note is from an affiliate entity that is involved in commercial real estate investments. These notes bear interest at market rates and are secured by the associated oil and natural gas properties and real estate, respectively. The following table sets forth the notes receivable as of December 31, 2004 and 2005:
                 
    December 31,
     
    2004   2005
         
Note receivable bearing interest at 10%, secured by oil and natural
gas properties due on April 1, 2006
   $ 1,000,000     $ —  
             
Note receivable bearing interest at bank prime plus 3.5% due on
March 31, 2015 — secured by real estate
     2,230,000       —  
             
    $ 3,230,000     $ —  
             
      The note secured by oil and natural gas properties was paid in full in November 2005.
(4)  Credit Facility
      On November 1, 1999, the Brothers Group entered into a Credit Facility (the Agreement) that permitted borrowings up to the lesser of (i) the borrowing base, or (ii) $20 million. The borrowing base was originally set at $8 million, was re-determined annually by the lender and decreased monthly based upon a schedule determined by the terms of the Agreement. Borrowings under the Agreement bore interest at a rate equal to the three-month LIBOR plus an add-on rate which increased from a minimum of 2.0% to a maximum of 3.5% based upon the amount borrowed as a percentage of the borrowing base with the interest payable monthly. The Agreement was secured by substantially all the oil and natural gas assets of the Brothers Group. The Brothers Group had $7.67 million and $5.7 million available on the borrowing base as of December 31, 2003 and 2004, respectively. The Brothers Group had $6.47 million outstanding at a rate of 4.0% and $2.0 million outstanding at a rate of 4.1% as of December 31, 2003 and 2004, respectively. The Brothers Group paid interest expense of $152,190, $114,335 and $65,962 for the years ended December 31, 2003,

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
2004 and 2005, respectively. The Agreement provided for certain restrictions, including but not limited to, limitations on additional borrowings, restrictions on use of proceeds, sales of collateral, and distributions to owners. It also required the Brothers Group to maintain certain quarterly debt service ratios. At December 31, 2004, the Brothers Group was in compliance with all aspects of the Agreement.
      On September 13, 2005, the Brothers Group replaced its Credit Agreement with a Senior Credit Facility (the “New Facility”) with a new lending group that permits borrowings in the lesser amount of (i) the borrowing base, or (ii) $75 million. The borrowing base under the New Facility, initially set at $30 million, is re-determined every six months and will be adjusted based upon changes in the fair market value of the Brothers Group’s oil and natural gas assets. Interest on the New Facility is payable monthly and is charged in accordance with the Brothers Group’s selection of a LIBOR rate plus 1.5% to 2.0%, or prime rate up to prime rate plus 0.50%, dependent on the percentage of the borrowing base which is drawn. Borrowings under this New Facility are due in September 2009. The New Facility contains certain loan covenants requiring minimum financial ratio coverages, involving the current ratio and EBITDA to interest expense. On September 13, 2005, the Brothers Group borrowed $17,402,000 from the new lending group for general corporate purposes, and to advance additional subordinated notes receivable in the amount of $12,588,030 to MBN Properties LP, which purchased oil and natural gas producing properties from PITCO. The Brothers Group’s interest rate at December 31, 2005 was 6.0%. The Brothers Group paid interest expense of $312,833 for the year ended December 31, 2005. Please refer to Note 17 regarding the private equity offering which closed on March 15, 2006 and for information about the payment in full of balances outstanding under the Senior Credit Facility.
(5)  Acquisitions and Divestiture
Energen Resources Acquisition
      In March 2003, BPPL acquired from Energen Resources an additional working interest in the SE Stinnett Unit and the Jordan University Unit for approximately $437,000 cash.
Pure Acquisition
      Effective May 1, 2003, BPPL acquired from Pure Resources a working interest in oil and natural gas properties for approximately $337,000. These properties consist of 68 wellbores located in the Iatan, East Howard field of Mitchell County, Texas. These properties are operated by Brothers Production Company Inc., and the acquisition was funded with cash.
Langlie Mattix Acquisition
      Effective October 1, 2003, BPPL acquired from Pecos Production Company a non-operated working interest in the Langlie Mattix Penrose Sand Unit (“LMPSU”) located in Lea County, New Mexico for approximately $700,000. The unit consisted of 94 wellbores. This unit is operated by Moriah Resources, Inc. and funded with cash.
Denton Devonian Acquisition
      Effective April 1, 2004, BPPL acquired from Fasken Oil and Ranch an additional working interest in the JM Denton lease for approximately $360,000. This property is operated by BPCI. Also acquired were working interests in a Fasken operated lease for approximately $650,000. Both of these leases are located in the Denton Devonian field in Lea County, New Mexico. This acquisition consisted of interests in 16 wellbores. The acquisition was funded with cash.

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
(6)  Partnership Investments
Accord Partnership
      In November 2002, BPPL purchased a 35.0% interest in Accord Resources, Ltd, (“Accord”), a partnership formed specifically to acquire various working interests in oil and natural gas properties located in Wise, Young and Jack County, Texas. The Brothers Group’s initial cash investment in Accord was approximately $459,000 and was accounted for by the equity method. Moriah Resources, Inc. was the general partner of Accord and responsible for daily operation of the properties.
      Cash distributions received by the Brothers Group from the partnership for the years ended December 31, 2003 and 2004 were approximately $140,000 and $105,000, respectively. Effective March 31, 2004, Accord was dissolved and the interests in the oil and natural gas properties were distributed to each of the partners, including the Brothers Group. On April 1, 2004, in conjunction with the other Accord partners, the Brothers Group sold all of its interests in the oil and natural gas properties to Aspen Integrated Oil and Gas, L.L.C. for approximately $2.0 million resulting in a gain on sale of assets of approximately $1.3 million.
      The following table reflects condensed net income information for the Accord Partnership on a gross basis:
                   
    Year Ended December 31,
     
    2003   2004
         
Oil and natural gas revenues
   $ 4,637,443     $ 1,129,819  
Oil derivative expense
     (254,440 )     —  
Other operating revenues
     178,505       174,517  
Direct lease operating expenses
     (2,162,386 )     (431,595 )
Production taxes
     (309,431 )     (71,105 )
Depletion, depreciation and accretion
     (927,467 )     (129,873 )
Other expenses
     (186,629 )     (7,958 )
             
 
Operating income
     975,595       663,805  
Other expense
     (76,996 )     (134,298 )
             
 
Partnership net income
   $ 898,599     $ 529,507  
             
MBN Properties LP and MBN Management LLC
      MBN Properties LP, a Delaware limited partnership, and its 1% general partner, MBN Management LLC,, a Delaware limited liability company, (collectively the “MBN Group”) were formed in 2005 to acquire and operate oil and natural gas producing properties in partnership with BPPL, Moriah Properties LP and certain third party investors. On July 22, 2005, BPPL advanced $1,176,684 in the form of $330 of paid in capital (32.98% partnership equity interest) and subordinated notes receivable of $1,176,354 to MBN Properties LP which utilized the capital to fund a deposit with The Prospective Investment and Trading Company, Ltd. (“PITCO”) and its affiliates for the purchase of oil and natural gas properties. BPPL advanced MBN Properties LP an additional $12,588,030 under the subordinated note receivable in conjunction with the closing of the PITCO acquisition. The subordinated note receivable from MBN Properties LP is due on July 15, 2012 and bears interest payable quarterly at the rate the Brothers Group pays under its New Facility plus 4%. BPPL also advanced $620,221 to fund the expenses of MBN Management LLC, the general partner of MBN Properties LP. Of this amount, $333 is for paid in capital (33.3% partnership equity interest) and the balance of $619,888 is in a subordinated note receivable from MBN Management LLC due July 15, 2012 and bearing interest at 7%. Please refer to Note 17 regarding the private

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
equity offering closed March 15, 2006 and for information about the payment in full of these subordinated notes receivable.
      While MBN Properties LP and MBN Management LLC are both variable interest entities under the guidelines of FAS FIN 46R, the Brothers Group accounts for its interest in these entities using the equity method since it is not the primary beneficiary of MBN Properties LP and no entity is the primary beneficiary of MBN Management LLC under the expected losses test of paragraph 14 of FAS FIN 46R.
      The following tables reflect condensed balance sheet and net loss information for MBN Properties LP on a gross basis:
           
    December 31,
    2005
     
Current assets
   $ 4,210,262  
Property, plant and equipment, at cost, net
     63,277,804  
Other assets
     923,961  
       
 
Total assets
   $ 68,412,027  
       
Current liabilities
   $ 2,049,690  
Long-term debt
     31,750,000  
Fair value of oil and gas swaps
     1,449,300  
Asset retirement obligation
     456,336  
Subordinated notes payable — partners
     34,837,072  
Partners’ deficit
     (2,130,371 )
       
 
Total liabilities and partners’ deficit
   $ 68,412,027  
       
           
    From Inception
    Through
    December 31,
    2005
     
Oil and natural gas revenues
   $ 5,877,119  
Oil derivative expense
     (2,221,625 )
Direct lease operating expenses
     (1,575,558 )
Production taxes
     (375,978 )
General and administrative expenses
     (453,842 )
Depletion, depreciation, amortization and accretion
     (1,637,171 )
       
 
Operating loss
     (387,055 )
Other expense
     (1,744,315 )
       
Partnership net loss
   $ (2,131,370 )
       

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
      The following tables reflect condensed balance sheet and net loss information for MBN Management LLC on a gross basis:
           
    December 31,
    2005
     
Current assets
   $ 1,233,338  
Other assets
     31,899  
       
 
Total assets
   $ 1,265,237  
       
Current liabilities
   $ 640,727  
Notes payable — affiliated entities
     1,952,753  
Members’ deficit
     (1,328,243 )
       
 
Total liabilities and members’ deficit
   $ 1,265,237  
       
           
    From Inception
    Through
    December 31,
    2005
     
General and administrative expenses
   $ (1,278,685 )
       
 
Operating loss
     (1,278,685 )
Other expense
     (50,558 )
       
 
Net loss
   $ (1,329,243 )
       
(7)  Related Party Transactions
      McGraw Brothers Investments, a Texas General partnership owned 25% by each of the four McGraw brothers, owns a 9% non-controlling limited partnership interest in a partnership which owns the building that the Brothers Group occupies. The lease expires in April 2008. Monthly rent is $3,903.
      The lease agreement had an original term of 60 months and expired on April 30, 2005. The lease was recently renewed for a period of 36 months. For the years ended December 31, 2003, 2004 and 2005, the Brothers Group recognized expense under the operating lease of $46,839 each year. As of December 31, 2005, future payments are as follows:
         
2006
   $ 46,839  
2007
   $ 46,839  
2008
   $ 15,613  
(8)  Commitments and Contingencies
      From time to time the Brothers Group is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Brothers Group is not currently a party to any proceeding that it believes, if determined in a manner adverse to the Brothers Group, could have a potential material adverse effect on its consolidated financial condition, results of operations or cash flows. The Brothers Group believes the likelihood of such a future event to be remote.
      Additionally, the Brothers Group’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Brothers Group could be adversely affected.
(9)  Business and Credit Concentrations
  Cash
      The Brothers Group maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. The Brothers Group has not experienced any losses in such accounts. The Brothers Group believes it is not exposed to any significant credit risk on its cash.
  Revenue and Trade Receivables
      Substantially all the Brothers Group’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Brothers Group’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Brothers Group has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2003, 2004 or 2005. The Brothers Group cannot ensure that such losses may not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of the Brothers Group’s sales is tabulated in Note 11.
(10)  Oil and Natural Gas Swaps
      Due to the volatility of oil and natural gas prices, the Brothers Group periodically enters into price-risk management transactions (e.g., swaps) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits the Brothers Group’s ability to benefit from increases in the price of oil and natural gas, it also reduces the Brothers Group’s potential exposure to adverse price movements. The Brothers Group’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices, and limit the Brothers Group’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes.
      All of these price risk management transactions are considered derivative instruments and accounted for in accordance with FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”. These derivative instruments are intended to hedge our price risk and may be considered hedges for economic purposes, but the Brothers Group has chosen not to designate these transactions as cash flow hedges. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings.
      By using derivative instruments to hedge exposures to changes in commodity prices, the Brothers Group exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Brothers Group, which creates repayment risk. The Brothers Group minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.
      For the years ended December 31, 2003, 2004 and 2005, the Brothers Group included in revenue realized and unrealized losses related to its oil and natural gas derivatives. There was no ineffectiveness

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
recognized during the years ended December 31, 2003, 2004 and 2005. The impact on total revenue from hedging activities for the three years ended December 31, 2003, 2004 and 2005 was as follows:
                         
    Year Ended December 31,
     
    2003   2004   2005
             
Crude oil derivative contract settlements
   $ (321,844 )   $ 46,576     $ (3,473,967 )
Natural gas derivative contract settlements
     (112,680 )     (79,900 )     —  
Unrealized change in fair value
     241,944       79,900       (1,381,157 )
                   
    $ (192,580 )   $ 46,576     $ (4,855,124 )
                   
      In its statement of cash flows for the nine months ended September 30, 2005, the Brothers Group classified $3,473,967 paid to settle crude oil derivative contracts as cash used in operating activities. In the accompanying statement of cash flows for the year ended December 31, 2005, the classification of such payments has been revised and they are classified as cash used in investing activities.
      The Brothers Group had no outstanding derivative instruments at December 31, 2004.
      On February 25, 2005, BPCI and BPPL entered into a NYMEX West Texas Intermediate crude oil swap of floating prices for fixed prices with Wells Fargo Bank, N.A. 7,000 Bbls per month for the period from October 2005 through December 2006. This contract was settled for a $2,008,767 cash payment on September 14, 2005.
      On May 25, July 5 and August 1, 2005 and January 13, 2006 and January 17, 2006, the Brothers Group entered into NYMEX West Texas Intermediate (“WTI”) crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:
                 
    Annual    
    Volume   Price
Calendar Year   (Bbls)   ($/Bbls)
         
2006
     209,605     $ 60.33  
2007
     160,558     $ 60.00  
2008
     150,199     $ 60.50  
2009
     145,270     $ 63.22  
2010
     136,875     $ 61.90  
      On September 29, 2005, December 2, 2005 and January 13, 2006, the Brothers Group entered into NYMEX Henry Hub natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:
                 
    Annual    
    Volume   Price
Calendar Year   (MMBtu)   ($/MMBtu)
         
2006
     442,338     $ 11.80  
2007
     400,998     $ 9.88  
2008
     369,311     $ 8.80  
2009
     346,385     $ 8.73  
2010
     324,120     $ 8.34  
      The purpose of the hedging program was to reduce the volatility of oil and natural gas prices and its impact on the predictability of the Brothers Group’s cash flows in light of its entering into an expanded credit facility on September 13, 2005, as noted above.

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
(11) Sales to Major Customers
      The Brothers Group operates as one business segment within the Permian Basin region. It sold crude oil and natural gas production representing 10% or more of total revenues for the years ended December 31, 2003, 2004 and 2005 as shown below:
                         
    2003   2004   2005
             
Amoco Production Company
     7%       8%       10%  
ConocoPhillips
     11%       8%       13%  
Navajo Crude Oil Marketing
     14%       16%       17%  
Plains Marketing, LP
     14%       15%       13%  
      In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of the Brothers Group’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. We believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.
(12) Asset Retirement Obligation
      In June 2001, the FASB issued FAS No. 143, which requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Brothers Group’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
      The Brothers Group adopted FAS No. 143 on January 1, 2003, which resulted in a net increase to oil and natural gas properties of $1.52 million and related liabilities of $1.76 million. These amounts reflect the ARO of the Brothers Group had the provisions of FAS No. 143 been applied since inception and resulted in a non-cash charge to earnings of $231,542. Going forward the Brothers Group will record an abandonment liability associated with its oil and natural gas wells when those assets are placed in service.
      The following table reflects the changes in the ARO during the years ended December 31, 2003, 2004 and 2005:
                         
    December 31,
     
    2003   2004   2005
             
Asset retirement obligation — beginning of period
   $ 1,759,071     $ 1,946,596     $ 1,553,516  
Liabilities incurred during the period
     312,050       16,408       823  
Liabilities associated with properties sold
     (84,530 )     (277,140 )     —  
Liabilities settled during the period
     —       —       (26,791 )
Current period accretion
     74,758       70,184       77,281  
Current period revisions to accretion expense
     (65,214 )     (124,724 )     (124,340 )
Current period revisions to oil and natural gas properties
     (49,539 )     (77,808 )     (1,120 )
                   
Asset retirement obligation — end of period
   $ 1,946,596     $ 1,553,516     $ 1,479,369  
                   
      The discount rate used in calculating the ARO was 4.0% in 2003, 4.1% in 2004 and 6.0% in 2005. These rates approximate the Brothers Group’s borrowing rates.

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
(13) Costs Incurred in Oil and Natural Gas Property Acquisition, Development and Exploration Activities
      Costs incurred by the Brothers Group in oil and natural gas property acquisition and development are presented below:
                             
    Year Ended December 31
     
    2003   2004   2005
             
Development costs
   $ 95,550     $ 1,259,427     $ 1,434,524  
Exploration costs
     812,436       345,143       204,968  
Acquisition costs:
                        
 
Proved properties
     3,637,125       1,231,047       157,078  
                   
   
Total
   $ 4,545,111     $ 2,835,617     $ 1,796,570  
                   
Brothers Group’s share of costs incurred by equity method investee
   $ 630,795     $ —     $ —  
                   
      Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas.
(14) Oil and Natural Gas Capitalized Costs
      Aggregate capitalized costs for the Brothers Group related to natural gas and oil production activities with applicable accumulated depreciation, depletion, and amortization are presented below:
                 
    December 31,
     
    2004   2005
         
Proved oil and natural gas properties
   $ 18,699,991     $ 20,001,062  
Accumulated depletion, depreciation and amortization
     (6,984,578 )     (7,583,307 )
             
    $ 11,715,413     $ 12,417,755  
             
(15) Net Proved Oil and Natural Gas Reserves (Unaudited)
      The proved oil and natural gas reserves of the Brothers Group have been estimated by an independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., as of December 31, 2002, 2003, 2004 and 2005. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
rules based on year-end prices. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, is shown below:
                     
    Oil and   Natural
    Condensate   Gas
    (MBbls)   (MMcf)
         
Total Proved Reserves
                
 
Balance, December 31, 2002
     2,233       6,859  
   
Purchase of minerals-in-place
     317       139  
   
Extensions and discoveries
     3       41  
   
Revisions of previous estimates
     346       623  
   
Production
     (219 )     (534 )
             
 
Balance, December 31, 2003
     2,680       7,128  
   
Purchase of minerals-in-place
     162       179  
   
Sales of minerals-in-place
     (30 )     (7 )
   
Extensions and discoveries
     96       421  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     44       53  
   
Revisions of previous estimates due to prices and performance
     529       190  
   
Production
     (242 )     (592 )
             
 
Balance, December 31, 2004
     3,239       7,372  
   
Purchase of minerals-in-place
     6       35  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     512       853  
   
Revisions of previous estimates due to prices and performance
     165       311  
   
Production
     (237 )     (558 )
             
 
Balance, December 31, 2005
     3,685       8,013  
             
Proved Developed Reserves
                
 
December 31, 2002
     2,233       6,859  
 
December 31, 2003
     2,679       7,128  
 
December 31, 2004
     3,239       7,372  
 
December 31, 2005
     3,213       7,346  
Brothers Group’s share of Proved Reserves of Equity Method Investee
                
 
December 31, 2002
     154       1,246  
 
December 31, 2003
     191       1,158  
 
December 31, 2004
     —       —  
 
December 31, 2005
     —       —  

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
(16) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves (Unaudited)
      Summarized in the following table is information for the Brothers Group with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future cash inflows are computed by applying year-end prices relating to the Brothers Group’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration, and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Brothers Group is a nontaxable entity.
                           
    December 31,
     
    2003   2004   2005
             
    (Thousands)
Future cash flows
   $ 116,612     $ 169,660     $ 279,102  
Future costs:
                        
 
Production
     (53,693 )     (73,605 )     (109,461 )
 
Development
     —       (120 )     (8,606 )
                   
Future net cash flows before income taxes
     62,919       95,935       161,035  
10% annual discount for estimated timing of cash flows
     (31,427 )     (48,811 )     (86,188 )
                   
Standardized measure of discounted net cash flows
   $ 31,492     $ 47,124     $ 74,847  
                   
Brothers Group’s share of standardized measure of discounted future net cash flows of equity method investee
   $ 2,984     $ —     $ —  
                   
      The Standardized Measure is based on the following oil and natural gas prices realized over the life of the properties at the wellhead as of the following dates:
                         
    December 31,
     
    2003   2004   2005
             
Oil (per Bbl)
   $ 29.32     $ 40.48     $ 56.83  
Natural gas (per MMBtu)
   $ 5.34     $ 5.23     $ 8.70  
      The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:
                           
    Year Ended December 31,
     
    2003   2004   2005
             
    (Thousands)
Increase (decrease):
                        
 
Sales, net of production costs
   $ (5,811 )   $ (9,566 )   $ (11,801 )
 
Net change in sales prices, net of production costs
     2,959       8,991       23,631  
 
Changes in estimated future development costs
     —       (59 )     (6,434 )
 
Extensions and discoveries, net of future production and development costs
     100       2,181       —  
 
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     —       642       12,630  
 
Previously estimated development costs incurred
     —       —       (120 )
 
Revisions of previous estimates due to prices and performance
     3,664       5,916       3,409  
 
Purchase of minerals-in place
     2,446       2,315       231  
 
Sales of minerals in place
     —       (250 )     —  

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BROTHERS GROUP
NOTES TO FINANCIAL STATEMENTS — (Continued)
                             
    Year Ended December 31,
     
    2003   2004   2005
             
    (Thousands)
 
Other
     1,104       2,809       2,303  
 
Accretion of discount
     2,353       2,653       3,874  
                   
   
Net increase
     6,815       15,632       27,723  
Standardized measure of discounted future net cash flows:
                        
   
Beginning of year
     24,677       31,492       47,124  
                   
   
End of year
   $ 31,492     $ 47,124     $ 74,847  
                   
      The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.
(17) Subsequent Event
      On March 15, 2006, Legacy Reserves LP (“Legacy”), the successor entity to the Moriah Group, completed a private equity offering (“Legacy Formation”) in which it issued 5,000,000 limited partnership units at a gross price of $17.00 per unit, netting $79.7 million after initial purchaser’s discount, placement agent’s fees and expenses. Simultaneous with the completion of this offering, Legacy purchased the oil and natural gas properties of the Brothers Group. Legacy also purchased the oil and natural gas properties owned by MBN Properties, LP.
      As an integral part of the Legacy Formation, Legacy entered into a new credit agreement with a new senior credit facility (the Legacy Facility) with the same lending group that participated in the New Facility of the Brothers Group. The terms of the Legacy Facility are essentially equivalent to those of the Brothers Group’s New Facility except that it permits borrowings in the lesser amount of (i) the borrowing base, or (ii) $300 million. The borrowing base under the Legacy Facility, initially set at $130 million, is re-determined every six months and will be adjusted based upon changes in the fair market value of the Group’s oil and gas assets. Interest on the Legacy Facility is payable monthly and is charged in accordance with Legacy’s selection of a LIBOR rate plus 1.25% to 1.875%, or prime rate up to prime rate plus 0.375%, dependent on the percentage of the borrowing base which is drawn. On March 15, 2006, Legacy borrowed $65.8 million from the new lending group as part of the Legacy Formation. The Moriah Group, the Brothers Group and MBN Properties LP each retired their outstanding balances under the New Facility with a total of $62.3 million being repaid, including accrued interest through the date of the Legacy Formation.
      Finally, as an integral part of the Legacy Formation, MBN Properties LP and MBN Management LLC have fully repaid the subordinated notes payable to the Moriah Group and Brothers Group, including accrued interest through the date of closing.

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Report of Independent Certified Public Accountants
Selected Interests of Paul T. Horne
Midland, Texas
      We have audited the accompanying balance sheets of the Selected Interests of Paul T. Horne, as defined in Note 1(a), at December 31, 2004 and 2005 and the related statements of operations, owner’s equity, and cash flows for each of the years in the three year period ended December 31, 2005. These financial statements are the responsibility of the Entity’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 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 Entity’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 financial statements referred to above present fairly, in all material respects, the financial position of the Selected Interests of Paul T. Horne at December 31, 2004 and 2005 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
      As discussed in Note 8 to the financial statements, effective January 1, 2003, Selected Interests of Paul T. Horne changed its method of accounting for asset retirement obligations.
  /s/ Johnson Miller & Co., CPA’s PC
Midland, Texas
May 5, 2006

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SELECTED INTERESTS OF PAUL T. HORNE
BALANCE SHEETS
                     
    December 31,
     
    2004   2005
         
ASSETS
                
Current assets:
                
 
Accounts receivable, oil and natural gas
   $ 41,874     $ 49,742  
             
   
Total current assets
     41,874       49,742  
             
Proved oil and natural gas properties, at cost, using the successful
efforts method of accounting:
     223,685       243,841  
Accumulated depletion, depreciation and amortization
     (55,193 )     (68,353 )
             
      168,492       175,488  
             
    $ 210,366     $ 225,230  
             
 
LIABILITIES AND OWNERS’ EQUITY
                
Current liabilities:
                
 
Accrued liabilities, oil and gas
   $ 14,604     $ 33,485  
 
Fair value of oil and gas swaps (Note 6)
     —       1,823  
 
Asset retirement obligation (Note 8)
     902       1,849  
             
   
Total current liabilities
     15,506       37,157  
Fair value of oil and natural gas swaps (Note 6)
     —       15,574  
Asset retirement obligation (Note 8)
     19,488       17,744  
             
Total liabilities
     34,994       70,475  
             
 
Commitments and contingencies (Note 4)
                
Owner’s equity
     175,372       154,755  
             
    $ 210,366     $ 225,230  
             
See accompanying notes to financial statements.

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SELECTED INTERESTS OF PAUL T. HORNE
STATEMENTS OF OPERATIONS
                             
    Year Ended December 31,
     
    2003   2004   2005
             
Revenues:
                        
 
Oil sales
   $ 68,012     $ 103,368     $ 142,993  
 
Natural gas sales
     31,642       37,001       49,231  
 
Realized and unrealized loss on oil and natural gas swaps (Note 6)
     —       —       (34,009 )
                   
   
Total revenues
     99,654       140,369       158,215  
                   
Expenses:
                        
 
Oil and natural gas production
     38,218       35,692       49,264  
 
Production and other taxes
     5,673       8,701       13,055  
 
Dry hole costs
     10,217       315       890  
 
Depletion, depreciation and accretion
     15,640       16,524       14,536  
 
Impairment of long-lived assets (Note 1)
     4,655       —       —  
 
(Gain) on sale of assets
     —       —       (330,740 )
                   
   
Total expenses, net of (gains) on sale of assets
     74,403       61,232       (252,995 )
                   
   
Income from continuing operations
     25,251       79,137       411,210  
                   
Other income (expense):
                        
Discontinued operations (Note 13)
                        
 
Income (loss) from operations
     (57 )     —       —  
 
Gain on disposal
     1,944       —       —  
                   
   
Income from discontinued operations
     1,887       —       —  
                   
Cumulative effect of accounting change (Note 8)
     (1,609 )     —       —  
                   
   
Net income
   $ 25,529     $ 79,137     $ 411,210  
                   
See accompanying notes to financial statements.

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SELECTED INTERESTS OF PAUL T. HORNE
STATEMENTS OF OWNER’S EQUITY
         
    Total
    Owner’s
    Equity
     
Balance, January 1, 2003
   $ 144,065  
Capital contributions
     31,270  
Distribution to owner
     (40,181 )
Net income
     25,529  
       
Balance, December 31, 2003
     160,683  
Capital contributions
     17,832  
Distribution to owner
     (82,280 )
Net income
     79,137  
       
Balance, December 31, 2004
     175,372  
Capital contributions
     20,258  
Distribution to owner
     (452,085 )
Net income
     411,210  
       
Balance, December 31, 2005
   $ 154,755  
       
See accompanying notes to financial statements.

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SELECTED INTERESTS OF PAUL T. HORNE
STATEMENTS OF CASH FLOWS
                             
    Year Ended December 31,
     
    2003   2004   2005
             
Cash flows from operating activities:
                        
 
Net income
   $ 25,529     $ 79,137     $ 411,210  
 
Adjustment to reconcile net income to net cash provided by operating activities:
                        
   
Dry hole costs
     10,217       315       890  
   
Depletion, depreciation, amortization and accretion
     15,640       16,524       14,536  
   
Impairment of long-lived assets
     4,655       —       —  
   
Loss on oil and natural gas swaps
     —       —       34,009  
   
Gain on sale of assets
     (1,944 )     —       (330,740 )
   
Non-cash effect of accounting change
     1,609       —       —  
 
Changes in assets and liabilities:
                        
   
(Increase) decrease in accounts receivable, oil and natural gas
     (7,937 )     (18,116 )     (7,868 )
   
Increase (decrease) in accrued liabilities, oil and natural gas
     507       4,735       18,881  
                   
   
Total adjustments
     22,747       3,458       (270,292 )
                   
   
Net cash provided by operating activities
     48,276       82,595       140,918  
                   
 
Cash flows from investing activities:
                        
   
Investment in oil and natural gas properties
     (41,487 )     (18,147 )     (23,519 )
   
Proceeds from sale of assets
     2,122       —       331,040  
   
Cash settlements on oil swaps
     —       —       (16,612 )
                   
   
Net cash provided by (used in) investing activities
     (39,365 )     (18,147 )     290,909  
                   
 
Cash flows from financing activities:
                        
   
Capital contributed by owner
     31,270       17,832       20,258  
   
Distributions to owner
     (40,181 )     (82,280 )     (452,085 )
                   
   
Net cash used in financing activities
     (8,911 )     (64,448 )     (431,827 )
                   
   
Net increase (decrease) in cash and cash equivalents
     —       —       —  
 
Cash and cash equivalents, beginning of period
     —       —       —  
                   
 
Cash and cash equivalents, end of period
   $ —     $ —     $ —  
                   
 
Non-Cash Investing and Financing Activities:
                        
   
Asset retirement obligations costs and liabilities
   $ 1,629     $ (1,952 )   $ (1,839 )
                   
See accompanying notes to financial statements.

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS
(1)  Summary of Significant Accounting Policies
     (a)  Basis of Presentation
      The accompanying financial statements include the accounts of Paul T. Horne, an individual (“PTH”), with respect to the selected interests in oil and natural gas properties he owns. PTH has other investments, such as real estate, which are not included in these financial statements. The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred.
     (b)  Organization and Description of Business
      Paul T. Horne, an individual, owns interests in oil and natural gas properties located primarily in the Permian Basin of West Texas and southeast New Mexico. Mr. Horne is a degreed petroleum engineer, who worked for Mobil Oil Corporation for 15 years in a variety of engineering and management roles primarily in the Permian Basin prior to joining Moriah Resources, Inc. (“MRI”) as its Operations Manager in January, 2000. Mr. Horne has participated with MRI and its affiliate Moriah Properties, Ltd. (“MPL”) in making certain acquisitions and drilling wells during his employment. Effective June 1, 2002, Mr. Horne executed a tax-free exchange with MPL trading his interest in approximately 16 properties for a 1.0% pro-rata interest across all of MPL’s properties, proportionately reduced to MPL’s actual working interest and net revenue interest. Subsequent to the exchange, Mr. Horne has participated at a 1.0% interest in all of MPL’s oil and natural gas property acquisitions and drilling projects. Mr. Horne is also the Vice President of Operations for MBN Management, LLC, an entity in which MPL owns a significant but non-controlling interest. On January 1, 2006, PTH contributed his oil and natural gas properties to H2K Holdings Ltd., a limited partnership which he owns on a 50/50 basis with his wife.
     (c)  Oil and Natural Gas Properties
      PTH accounts for oil and natural gas properties by the successful efforts method. Under this method of accounting, costs relating to the acquisition of and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities.
      Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. FAS No. 19 requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped, and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by PTH’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., and are subject to future revisions based on availability of additional information. PTH’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 8, PTH follows FAS No. 143. Under FAS No. 143, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by PTH’s engineers using existing regulatory requirements and anticipated future inflation rates.

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
      Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation.
      Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. PTH assesses impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using oil and natural gas prices as of the last day of the statement period held constant. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2003, 2004 and 2005, the estimated undiscounted future cash flows for PTH’s proved oil and natural gas properties exceeded the net capitalized costs, and no impairment was required to be recognized. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Costs related to unproved mineral interests that are individually insignificant are amortized over the shorter of the exploratory period or the lease/concession holding period which is typically three years in the Permian Basin.
     (d)  Oil and Natural Gas Reserve Quantities
      PTH’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche Petroleum Consultants, Ltd. prepares a reserve and economic evaluation of all PTH’s properties on a well-by-well basis utilizing information provided to it by PTH and utilizing information available from state agencies that collect information reported to it by the operators of PTH’s properties.
      Reserves and their relation to estimated future net cash flows impact PTH’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. PTH prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve report. The accuracy of PTH’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
      PTH’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.
     (e)  Income Taxes
      No provision for income taxes is made in PTH’s financial statements because the taxable income or loss of PTH is included in the income tax returns of the owner.
     (f)  Derivative Instruments and Hedging Activities
      PTH periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. Currently, these transactions are swaps. PTH accounts for these activities pursuant to FAS No. 133 — Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities.

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
      PTH does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices. Therefore, the mark to market of these instruments is recorded in current earnings (see Note 6).
     (g)  Use of Estimates
      PTH has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of oil and natural gas reserves, accrued revenue and expenses, future cash flows from oil and natural gas properties, and depreciation, depletion and amortization.
     (h)  Revenue Recognition
      Sales of crude oil and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of PTH’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. As a result, PTH’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. PTH believes that the pricing provisions of its oil and natural gas contracts are customary in the industry.
      PTH currently uses the “net-back” method of accounting for transportation arrangements of his natural gas sales. PTH sells natural gas at the wellhead and collects a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by his purchasers and reflected in the wellhead price. PTH’s contracts with respect to the sale of his natural gas produced, with one immaterial exception, provide a net price payment. That is, when PTH is paid for his natural gas by his purchasers, PTH receives a price which is net of any costs incurred for treating, transportation, compression, etc. In accordance with the terms of his contracts, the payment statements PTH receives from his purchasers show a single net price without any detail as to treating, transportation, compression, etc. Thus, his revenues are recorded at this single net price.
      Natural gas imbalances occur when PTH sells more or less than his entitled ownership percentage of total natural gas production. Any amount received in excess of his share is treated as a liability. If PTH receives less than his entitled share the underproduction is recorded as a receivable. PTH did not have any significant natural gas imbalance positions as of December 31, 2003, 2004 or 2005.
     (i)  Environmental
      PTH is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require PTH 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. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments are fixed and readily determinable.

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
     (j)  Recently Issued Accounting pronouncements
      Emerging Issues Task Force (“EITF”) Issue 04-9 and Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) FAS 19-1: Statement of Financial Accounting Standards (“FAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” requires the cost of drilling an exploratory well to be capitalized pending determination of whether the well has found proved reserves. If this determination cannot be made at the conclusion of drilling, FAS No. 19 sets out additional requirements for continuing to carry the cost of the well as an asset. These requirements include firm plans for further drilling and a one-year time limitation on continued capitalization in certain instances. In April 2005, the FASB issued FSP FAS 19-1, which we adopted effective January 1, 2005. This FSP amends FAS No. 19 to allow continued capitalization when (i) the well has found a sufficient quantity of reserves to justify proceeding with the project plan and (ii) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project which may include more than one exploratory well if the reserves are intended to be extracted in a single integrated operation. The FSP also requires increased disclosures. Adoption of this rule did not have a material impact on our earnings in 2005. If this FSP had been applied to 2004, it would not have had a material effect on his earnings for that year.
      FAS No. 153: In 2004, the FASB issued FAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29,” which became effective July 1, 2005. With certain exceptions, this requires exchanges of nonmonetary assets to be recorded at fair value. Previously, these transactions were generally recorded at book value. This pronouncement results in reporting in earnings, gains and losses on exchanges of nonmonetary assets. Adoption of this rule did not have a material impact on either his earnings or balance sheet in 2005.
      FAS No. 154: In 2005, the FASB issued FAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FAS No. 3,” which is effective January 1, 2006. Opinion 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This Statement requires retrospective application (restatement) to prior periods’ financial statements of changes in accounting principle. This Statement also applies to changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.
      FAS Interpretation No. 47: In March 2005, the FASB issued FAS Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FAS Statement No. 143,” “Accounting for Asset Retirement Obligations” which is effective no later than December 31, 2005. This pronouncement clarifies that the term “conditional asset retirement obligation” as used in FAS Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. This interpretation is not expected to have a material impact on either his earnings or balance sheet.
(2)  Acquisitions and Divestiture
  Energen Resources Acquisition
      In March 2003, PTH acquired from Energen Resources an additional working interest in the SE Stinnett Unit and the Jordan University Unit for approximately $4,000 cash.

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
  Pure Acquisition
      Effective May 1, 2003, PTH acquired from Pure Resources a working interest in oil and natural gas properties for approximately $3,000. These properties consist of 68 wellbores located in the Iatan, East Howard field of Mitchell County, Texas. These properties are operated by Brothers Production Company Inc., and the acquisition was funded with cash.
  Langlie Mattix Acquisition
      Effective October 1, 2003, PTH acquired from Pecos Production Company a non-operated working interest in the Langlie Mattix Penrose Sand Unit (“LMPSU”) located in Lea County, New Mexico for approximately $7,000. This unit is operated by Moriah Resources, Inc. and funded with cash.
  Denton Devonian Acquisition
      Effective April 1, 2004, PTH acquired from Fasken Oil and Ranch an additional working interest in the JM Denton lease for approximately $6,000. This property is operated by BPCI. Also acquired were working interests in a Fasken operated lease for approximately $10,000. Both of these leases are located in the Denton Devonian field in Lea County, New Mexico. The acquisition was funded with cash.
(3)  Related Party Transactions
      PTH serves as Operations Manager for Moriah Resources, Inc. (“MRI”) and has done so since January, 2000. Mr. Horne has participated with MRI and its affiliate Moriah Properties, Ltd. (“MPL”) in making certain acquisitions and drilling wells during his employment. Effective June 1, 2002, Mr. Horne executed a like kind exchange with MPL trading his interest in approximately 16 properties for a 1.0% pro-rata interest across all of MPL’s properties, proportionately reduced to MPL’s actual working interest and net revenue interest. Subsequent to the exchange, Mr. Horne has participated at a 1.0% interest in all of MPL’s oil and natural gas property acquisitions and drilling projects. Mr. Horne is also the Vice President of Operations for MBN Management, LLC, an entity in which MPL owns a significant but non-controlling interest. MRI performs certain accounting functions for PTH as part of its routine accounting activities.
(4)  Commitments and Contingencies
      PTH’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of PTH could be adversely affected.
(5)  Business and Credit Concentrations
  Revenue Receivables
      Substantially all PTH’s accounts receivable result from oil and natural gas sales. This concentration of customers may impact PTH’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, PTH has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2003, 2004, or 2005. PTH cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of PTH’s sales is tabulated in Note 7.

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
(6)  Oil and Natural Gas Swaps
      Due to the volatility of oil and natural gas prices, PTH periodically enters into price-risk management transactions (e.g., swaps, collars, and floors) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits PTH’s ability to benefit from increases in the price of oil and natural gas, it also reduces PTH’s potential exposure to adverse price movements. PTH’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices, and limit PTH’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes.
      All of these price risk management transactions are considered derivative instruments and accounted for in accordance with FAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” These derivative instruments are intended to hedge our price risk and may be considered hedges for economic purposes, but PTH has chosen not to designate these transactions as cash flow hedges. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings.
      By using derivative instruments to hedge exposures to changes in commodity prices, PTH exposes himself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes PTH creates repayment risk. PTH minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.
      PTH had no commodity derivative contract activity for the years ended December 31, 2003, 2004 and 2005. The impact on total revenue from hedging activities for the years ended December 31, 2003, 2004 and 2005 was as follows:
                         
    Year Ended December 31,
     
    2003   2004   2005
             
Crude oil derivative contract settlements
   $ —     $ —     $ (16,612 )
Unrealized change in fair value
     —       —       (17,397 )
                   
    $ —     $ —     $ (34,009 )
                   
      In its statement of cash flows for the nine months ended September 30, 2005, the Selected Interests of Paul T. Horne classified $16,612 paid to settle crude oil derivative contracts as cash used in operating activities. In the accompanying statement of cash flows for the year ended December 31, 2005, the classification of such payments has been revised and they are classified as cash used in investing activities.
      On May 25, July 5, August 1, and December 2, 2005 and January 13, 2006, PTH entered into NYMEX West Texas Intermediate (“WIT”) crude oil swaps paying floating prices and receiving fixed prices for a portion of future production as indicated below.
                     
    Annual    
Calendar   Volume   Price
Year   (Bbls)   ($/Bbls)
         
  2006       3,127     $ 60.39  
  2007       2,376     $ 60.00  
  2008       2,222     $ 60.50  
  2009       2,310     $ 63.22  
  2010       2,179     $ 61.90  

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
      On September 29, 2005 and January 13, 2006, PTH entered into NYMEX Henry Hub natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of his future production as indicated below.
                     
    Annual    
Calendar   Volume   Price
Year   (MMBtu)   ($/MMBtu)
         
  2006       7,052     $ 11.80  
  2007       6,393     $ 9.88  
  2008       5,240     $ 8.80  
  2009       5,524     $ 8.73  
  2010       5,167     $ 8.34  
      The purpose of the hedging program was to reduce the volatility of oil and natural gas prices and improving the predictability of PTH’s cash flows.
(7)  Sales to Major Customers
      PTH operates as one business segment within the Permian Basin region. It sold crude oil and natural gas production representing 10% or more of total revenues for the years ended December 31, 2003, 2004 and 2005 as shown below:
                         
    2003   2004   2005
             
Amoco Production Company
     7 %     9 %     10 %
ConocoPhillips
     14 %     9 %     14 %
Navajo Crude Oil Marketing
     15 %     17 %     16 %
Plains Marketing, LP
     16 %     20 %     23 %
      In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of PTH’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. We believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.
(8)  Asset Retirement Obligation
      In June 2001, the FASB issued FAS No. 143, which requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at PTH’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
      PTH adopted FAS No. 143 on January 1, 2003, which resulted in a net increase to oil and natural gas properties of approximately $18,200 and related liabilities of approximately $19,800. These amounts reflect the ARO of PTH had the provisions of FAS No. 143 been applied since inception and resulted in a non-cash charge to earnings of approximately $1,600. Going forward PTH will record an abandonment liability associated with its oil and natural gas wells when those assets are placed in service.

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
      The following table reflects the changes of the ARO during the years ended December 31, 2003, 2004 and 2005:
                         
    December 31,
     
    2003   2004   2005
             
Asset retirement obligation — beginning of period
   $ 19,807     $ 21,766     $ 20,390  
Liabilities incurred during the period
     3,300       52       72  
Liabilities settled during the period
     (498 )     —       (452 )
Current period accretion
     828       932       1,034  
Current period revisions to accretion expense
     —       (356 )     8  
Current period revisions to oil and natural gas properties
     (1,671 )     (2,004 )     (1,459 )
                   
Asset retirement obligation — end of period
   $ 21,766     $ 20,390     $ 19,593  
                   
      The discount rate used in calculating the ARO was 4.0% in 2003, 4.1% in 2004 and 6.0% in 2005, respectively. These rates approximate PTH’s borrowing rates.
(9)  Costs Incurred in Oil and Natural Gas Property Acquisition and Development
      Costs incurred by PTH in natural gas and oil property acquisition and development are presented below:
                             
    Year Ended December 31,
     
    2003   2004   2005
             
Development costs
   $ (1,671 )   $ 14,794     $ 16,939  
Exploration costs
     10,217       315       890  
Acquisition costs:
                        
 
Unproved properties
     5,355       —       —  
 
Proved properties
     48,566       1,086       3,851  
                   
   
Total
   $ 62,467     $ 16,195     $ 21,680  
                   
      Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas.
(10)  Oil and Natural Gas Capitalized Costs
      Aggregate capitalized costs for PTH related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization are presented below:
                         
    December 31,
     
    2003   2004   2005
             
Proved oil and natural gas properties
   $ 207,806     $ 223,685     $ 243,841  
Accumulated depletion, depreciation and amortization
     (39,246 )     (55,193 )     (68,353 )
                   
    $ 168,560     $ 168,492     $ 175,488  
                   
(11)  Net Proved Oil and Natural Gas Reserves (Unaudited)
      The proved oil and natural gas reserves of PTH have been estimated by an independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., as of December 31, 2002, 2003, 2004 and 2005. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
based on year-end prices. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, is shown below:
                     
    Oil and   Natural
    Condensate   Gas
    (MBbls)   (MMcf)
         
Total Proved Reserves
                
 
Balance, December 31, 2002
     25.8       105.4  
   
Purchase of minerals-in-place
     4.6       2.4  
   
Extensions and discoveries
     0.1       0.7  
   
Revisions of previous estimates
     4.8       9.5  
   
Production
     (2.4 )     (8.2 )
             
 
Balance, December 31, 2003
     32.9       109.8  
   
Purchase of minerals-in-place
     2.3       2.6  
   
Extensions and discoveries
     1.3       4.4  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     0.7       0.4  
   
Revisions of previous estimates due to prices and performance
     6.1       3.1  
   
Production
     (2.8 )     (8.4 )
             
 
Balance, December 31, 2004
     40.5       111.9  
   
Purchase of minerals-in-place
     —       —  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     8.7       14.1  
   
Revisions of previous estimates due to prices and performance
     2.9       6.1  
   
Production
     (2.9 )     (8.2 )
             
 
Balance, December 31, 2005
     49.2       123.9  
             
Proved Developed Reserves
                
 
December 31, 2002
     25.8       105.4  
 
December 31, 2003
     32.9       109.8  
 
December 31, 2004
     40.5       111.9  
 
December 31, 2005
     41.4       112.8  
(12)  Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves (Unaudited)
      Summarized in the following table is information for PTH with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future cash inflows are computed by applying year-end prices relating to PTH’s proved reserves to the year-end quantities of those reserves. Future

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
production, development, site restoration, and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.
                           
    December 31,
     
    2003   2004   2005
             
    (Thousands)
Future cash flows
   $ 1,554     $ 2,229     $ 3,886  
Future costs:
                        
 
Production
     (707 )     (983 )     (1,505 )
 
Development
     —       (2 )     (145 )
                   
Future net cash flows before income taxes
     847       1,244       2,236  
10% annual discount for estimated timing of cash flows
     (432 )     (644 )     (1,230 )
                   
Standardized measure of discounted net cash flows
   $ 415     $ 600     $ 1,006  
                   
      The Standardized Measure is based on the following oil and natural gas prices realized over the life of the properties at the wellhead as of the following dates:
                         
    December 31,
     
    2003   2004   2005
             
Oil (per Bbl)
   $ 29.35     $ 40.47     $ 56.84  
Natural gas (per MMBtu)
   $ 5.33     $ 5.20     $ 8.69  
      The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:
                             
    Year Ended
    December 31,
     
    2003   2004   2005
             
    (Thousands)
Increase (decrease):
                        
 
Sales, net of production costs
   $ (56 )   $ (96 )   $ (130 )
 
Net change in sales prices, net of production costs
     47       97       325  
 
Changes in estimated future development costs
     —       (1 )     (109 )
 
Extensions and discoveries, net of future production and development costs
     2       24       —  
 
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     —       9       207  
 
Previously estimated development costs incurred
     —       —       (2 )
 
Revisions of previous estimates due to prices and performance
     49       70       106  
 
Purchase of minerals-in place
     36       36       —  
 
Other
     (1 )     12       (41 )
 
Accretion of discount
     28       34       50  
                   
   
Net increase
     105       185       406  
Standardized measure of discounted future net cash flows:
                        
 
Beginning of year
     310       415       600  
                   
 
End of year
   $ 415     $ 600     $ 1,006  
                   

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SELECTED INTERESTS OF PAUL T. HORNE
NOTES TO FINANCIAL STATEMENTS — (Continued)
      The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.
(13)  Discontinued Operations
      PTH has disposed of certain producing oil and natural properties which meet the guidelines for treatment as discontinued operations under FAS 144. The following table sets for the operating results for these discontinued operations:
                           
    Year Ended December 31,
     
    2003   2004   2005
             
Oil sales
   $ 282     $ —     $ —  
Natural gas sales
     —       —       —  
Oil and natural gas production expenses
     (326 )     —       —  
Production and other taxes
     (13 )     —       —  
                   
 
Income (loss) from discontinued operations
     (57 )     —       —  
                   
 
Gain on disposal
     1,944       —       —  
                   
      —       —       —  
 
Total income from discontinued operations
   $ 1,887     $ —     $ —  
                   
(14)  Subsequent Event
      On March 15, 2006, Legacy Reserves LP (“Legacy”), the successor entity to the Moriah Group, completed a private equity offering (“Legacy Formation”) in which it issued 5,000,000 limited partnership units at a gross price of $17.00 per unit. Simultaneous with the completion of this offering, Legacy purchased the oil and natural gas properties of H2K Holdings Ltd. H2K Holdings Ltd. exchanged its oil and natural gas properties for limited partnership units. The Moriah Group has been treated as the acquiring entity in the formation transaction of Legacy. Legacy was formed in October 2005.

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Report of Independent Certified Public Accountants
Selected Properties of Charities Support Foundation Inc. and Affiliates
Midland, Texas
      We have audited the accompanying combined balance sheets of the Selected Properties of Charities Support Foundation Inc. and Affiliates, as defined in Note 1(a), at December 31, 2004 and 2005 and the related combined statements of operations, equity, and cash flows for the two year period ended December 31, 2005. These financial statements are the responsibility of the Foundations’ 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 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 Foundations’ 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 combined financial statements referred to above present fairly, in all material respects, the financial position of the Selected Properties of Charities Support Foundation Inc and Affiliates at December 31, 2004 and 2005, and the results of its operations and its cash flows for the two year period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
  /s/ Johnson Miller & Co., CPA’s PC
Midland Texas
May 5, 2006

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
COMBINED BALANCE SHEETS
                     
    December 31,
     
    2004   2005
         
ASSETS
Current assets:
                
Accounts receivable, oil and natural gas
   $ 747,788     $ 790,186  
             
 
Total current assets
     747,788       790,186  
             
Proved oil and gas properties, at cost, using the successful efforts method of accounting
     4,631,708       4,774,454  
Accumulated depletion, depreciation and amortization
     (343,576 )     (632,670 )
             
      4,288,132       4,141,784  
             
    $ 5,035,920     $ 4,931,970  
             
 
LIABILITIES AND EQUITY
Current liabilities:
                
 
Accrued liabilities, oil and natural gas
   $ 295,805     $ 283,966  
 
Accrued retirement obligation (Note 6)
     —       18,449  
             
   
Total current liabilities
     295,805       302,415  
Asset retirement obligation (Note 6)
     204,448       185,375  
             
Total liabilities
     500,253       487,790  
             
 
Commitments and contingencies (Note 3)
                
Equity
     4,535,667       4,444,180  
             
    $ 5,035,920     $ 4,931,970  
             
See accompanying notes to combined financial statements.

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
COMBINED STATEMENTS OF OPERATIONS
                     
    Year Ended December 31,
     
    2004   2005
         
Revenues:
                
 
Oil sales
   $ 993,638     $ 1,251,599  
 
Natural gas sales
     408,758       595,302  
             
   
Total revenues
     1,402,396       1,846,901  
             
Expenses:
                
 
Oil and natural gas production
     358,797       528,430  
 
Production and other taxes
     88,908       118,651  
 
General and administrative
     32,086       43,001  
 
Depletion, depreciation and accretion
     330,828       286,913  
 
Impairment of long-lived assets
     —       5,530  
             
   
Total expenses
     810,619       982,525  
             
   
Net income
   $ 591,777     $ 864,376  
             
See accompanying notes to combined financial statements.

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
COMBINED STATEMENTS OF EQUITY
         
    Total
    Equity
     
Balance, January 1, 2003
   $ —  
Donated oil and natural gas property
     2,983,400  
       
Balance, December 31, 2003
     2,983,400  
Donated oil and natural gas property
     1,278,600  
Capital contributions
     152,512  
Distributions to foundations
     (470,622 )
Net income
     591,777  
       
Balance, December 31, 2004
     4,535,667  
Capital contributions
     132,580  
Distributions to foundations
     (1,088,443 )
Net income
     864,376  
       
Balance, December 31, 2005
   $ 4,444,180  
       
See accompanying notes to combined financial statements.

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
COMBINED STATEMENTS OF CASH FLOWS
                       
    Year Ended
    December 31,
     
    2004   2005
         
Cash flows from operating activities:
                
 
Net income
   $ 591,777     $ 864,376  
 
Adjustment to reconcile net income to net cash provided by operating activities:
                
   
Depletion, depreciation, amortization and accretion
     330,828       286,913  
   
Impairment of long-lived assets
     —       5,530  
 
Changes in assets and liabilities:
                
   
(Increase) decrease in accounts receivable, oil and natural gas
     (747,788 )     (42,398 )
   
Increase (decrease) in accrued liabilities, oil and natural gas
     295,805       (11,839 )
             
     
Total adjustments
     (121,155 )     238,206  
             
     
Net cash provided by operating activities
     470,622       1,102,582  
             
Cash flows from investing activities:
                
 
Investment in oil and natural gas properties
     (152,512 )     (146,719 )
             
     
Net cash used in investing activities
     (152,512 )     (146,719 )
             
Cash flows from financing activities:
                
 
Capital contributed
     152,512       132,580  
 
Distributions to foundations
     (470,622 )     (1,088,443 )
             
     
Net cash used in financing activities
     (318,110 )     (955,863 )
             
     
Net increase (decrease) in cash and cash equivalents
     —       —  
Cash and cash equivalents, beginning of period
     —       —  
             
Cash and cash equivalents, end of period
   $ —     $ —  
             
Non-Cash Investing and Financing Activities:
                
 
Asset retirement obligation costs and liabilities, net
   $ (4,638 )   $ 594  
             
 
Contribution of oil and gas properties
   $ 1,278,600     $ —  
             
See accompanying notes to combined financial statements.

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
     (a) Basis of Presentation
      The accompanying combined financial statements include the activities of Charities Support Foundation, Inc. (“CSFI”), Moriah Foundation, Inc. (“MFI”), and Cary Brown Family Foundation (“CBFF”) with respect to certain oil and natural gas properties contributed to them by Dale A. Brown and Cary D. Brown on December 31, 2003 and January 1, 2004. All significant intercompany accounts and transactions have been eliminated in consolidation. The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. As used herein, the term Charitable Foundations refers to all of these entities on a combined basis unless the context specifies otherwise.
     (b) Organization and Description of Business
      The Charitable Foundations operate as three separate public charities with offices in Colorado Springs, Colorado. Among other investments the Charitable Foundations own interests in oil and natural gas producing properties primarily located in the Permian Basin of West Texas and southeast New Mexico. The Charitable Foundations are comprised of Charities Support Foundation, Inc. (“CSFI”), Moriah Foundation, Inc. (“MFI”), and Cary Brown Family Foundation (“CBFF”). Charities Support Foundation, Inc. was organized as a Section 501(c)(3) and Section 509(a)(3) non-profit organization on July 31, 1997 under the laws of the State of Colorado, and provides support to qualifying charitable purposes and management services to other charitable entities, donor advised funds, charitable trusts and charitable annuities. CSFI in this capacity provides services to both MFI and CBFF. Moriah Foundation, Inc. was organized on May 26, 2000 under the laws of the State of Colorado as a Section 501(c)(3) and Section 509(a)(3) non-profit supporting organization to Christian Community Foundation. Cary Brown Family Foundation was organized on November 19, 2003, under the laws of the State of Texas as a Section 501(c)(3) and Section 509(a)(3) non-profit supporting organization to Christian Community Foundation. In December 2003 and January 2004 Dale and Rita Brown contributed to CSFI and MFI, and Cary and Jill Brown contributed to CSFI and CBFF, undivided interests in producing oil and natural gas properties in which Moriah Properties, Ltd and Moriah New Mexico, Ltd. also own interests. CSFI owns working interests burdened by net profits interests owned by MFI and CBFF. CSFI has contracted with Moriah Resources, Inc. to provide certain accounting and management services related to the ownership of these oil and natural gas interests. Dale Brown and Cary Brown each own 50% of the common stock of Moriah Resources Inc. Dale Brown serves on the board of Christian Community Foundation. Cary Brown serves on the board of CSFI.
     (c) Oil and Natural Gas Properties
      The Charitable Foundations accounts for oil and natural gas properties by the successful efforts method. Under this method of accounting, costs relating to the acquisition of and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities.
      Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. FAS No. 19 requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped, and that capitalized development costs (wells and related

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by the Charitable Foundations’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., and are subject to future revisions based on availability of additional information. The Charitable Foundations’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 6, the Charitable Foundations follows FAS No. 143. Under FAS No. 143, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Asset retirement costs are estimated by the Charitable Foundations’s engineers using existing regulatory requirements and anticipated future inflation rates.
      Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation.
      Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. The Charitable Foundations assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using oil and natural gas prices as of the last day of the statement period held constant. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2003, 2004 and 2005, the estimated undiscounted future cash flows for the Charitable Foundations’ proved oil and natural gas properties exceeded the net capitalized costs, and no impairment was required to be recognized. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Costs related to unproved mineral interests that are individually insignificant are amortized for impairment over the shorter of the exploratory period or the lease/concession holding period which is typically three years in the Permian Basin.
     (d) Oil and Gas Reserve Quantities
      The Charitable Foundations’ estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche Petroleum Consultants, Ltd. prepares a reserve and economic evaluation of all the Charitable Foundations’ properties on a well-by-well basis utilizing information provided to it by the Charitable Foundations and utilizing information available from state agencies that collect information reported to it by the operators of the Charitable Foundations’ properties.
      Reserves and their relation to estimated future net cash flows impact the Charitable Foundations’ depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Charitable Foundations prepare their reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve report. The accuracy of the Charitable Foundations’ reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
      The Charitable Foundations’ proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
     (e) Income Taxes
      No provision for income taxes is made in the Charitable Foundations’ combined financial statements because the net profits or losses of the Charitable Foundations are not taxable.
     (f) Use of Estimates
      Management of the Charitable Foundations has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of oil and natural gas reserves, accrued revenue and expenses, future cash flows from oil and natural gas properties, and depreciation, depletion and amortization.
     (g) Revenue Recognition
      Sales of crude oil and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of CSFI’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. As a result, CSFI’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. CSFI believes that the pricing provisions of its oil and natural gas contracts are customary in the industry.
      We currently use the “net-back” method of accounting for transportation arrangements of our natural gas sales. We sell natural gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by our purchasers and customers and reflected in the wellhead price. Our contracts with respect to the sale of our natural gas produced, with one immaterial exception, provide us with a net price payment. That is, when we are paid for our natural gas by our purchasers, we receive a price which is net of any costs incurred for treating, transportation, compression, etc. In accordance with the terms of our contracts, the payment statements we receive from our purchasers show a single net price without any detail as to treating, transportation, compression, etc. Thus, our revenues are recorded at this single net price. In the event we are billed separately for transportation charges, we would record the revenue at a gross sales price and the transportation charge as an expense in the “Oil and natural gas production expense” line item on our income statement.
      Natural gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant natural gas imbalance positions as of December 31, 2004 or 2005.
     (h) Recently Issued Accounting pronouncements
      Emerging Issues Task Force (“EITF”) Issue 04-9 and Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) FAS 19-1: Statement of Financial Accounting Standards (“FAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” requires the cost of drilling an exploratory well to be capitalized pending determination of whether the well has found proved reserves. If

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
this determination cannot be made at the conclusion of drilling, FAS No. 19 sets out additional requirements for continuing to carry the cost of the well as an asset. These requirements include firm plans for further drilling and a one-year time limitation on continued capitalization in certain instances. In April 2005, the FASB issued FSP FAS 19-1, which we adopted effective January 1, 2005. This FSP amends FAS No. 19 to allow continued capitalization when (i) the well has found a sufficient quantity of reserves to justify proceeding with the project plan and (ii) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project which may include more than one exploratory well if the reserves are intended to be extracted in a single integrated operation. The FSP also requires increased disclosures. Adoption of this rule did not have a material impact on earnings in 2005. If this FSP had been applied to 2004, it would not have had a material effect on our earnings for that year.
      FAS No. 153: In 2004, the FASB issued FAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29,” which became effective July 1, 2005. With certain exceptions, this requires exchanges of nonmonetary assets to be recorded at fair value. Previously, these transactions were generally recorded at book value. This pronouncement results in reporting in earnings, gains and losses on exchanges of nonmonetary assets. Adoption of this rule did not have a material impact on either our earnings or balance sheet in 2005.
      FAS No. 154: In 2005, the FASB issued FAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FAS No. 3,” which is effective January 1, 2006. Opinion 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This Statement requires retrospective application (restatement) to prior periods’ financial statements of changes in accounting principle. This Statement also applies to changes required by a new accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.
      FAS Interpretation No. 47: In March 2005, the FASB issued FAS Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FAS Statement No. 143,” “Accounting for Asset Retirement Obligations” which is effective no later than December 31, 2005. This pronouncement clarifies that the term “conditional asset retirement obligation” as used in FAS Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. This interpretation is not expected to have a material impact on either our earnings or combined balance sheet.
     (i) Environmental
      The Charitable Foundations are subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Charitable Foundations 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. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments are fixed and readily determinable.

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(2) Related Party Transactions
      CSFI has contracted with Moriah Resources, Inc. to provide certain accounting and management services related to the ownership of these oil and natural gas interests. CSFI paid fees of $13,255 and $39,518 to Moriah Resources, Inc. for the years ended December 31, 2004 and 2005.
(3) Commitments and Contingencies
      From time to time the Charitable Foundations are parties to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Charitable Foundations are not currently a party to any proceeding that it believes, if determined in a manner adverse to the Charitable Foundations, could have a potential material adverse effect on its financial condition, results of operations or cash flows. The Charitable Foundations believe the likelihood of such a future event to be remote.
      Additionally, the Charitable Foundations’ operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Charitable Foundations could be adversely affected.
(4) Business and Credit Concentrations
Revenue and Trade Receivables
      Substantially all the Charitable Foundations’ accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Charitable Foundations’ overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Charitable Foundations have not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2005. The Charitable Foundations cannot ensure that such losses may not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of the Charitable Foundations’ sales is tabulated in Note 5.
(5) Sales to Major Customers
      The Charitable Foundations operate as one business segment within the Permian Basin region. They sold crude oil and natural gas production representing 10% or more of total revenues for the years ended December 31, 2004 and 2005:
                 
    2004   2005
         
ConocoPhillips
     9 %     14 %
Navajo Crude Oil Marketing
     17 %     16 %
Plains Marketing, LP
     20 %     24 %
      In the exploration, development and production business, production is normally sold to relatively few customers. Substantially all of the Charitable Foundations’ customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. We believe that the loss of any of our major purchasers would not have a long-term material adverse effect on our operations.

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(6) Asset Retirement Obligation
      In June 2001, the FASB issued FAS No. 143, which requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Charitable Foundations’ credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
      The following table reflects the changes of the ARO during the years ended December 31, 2003, 2004 and 2005:
                         
    December 31,
     
    2003   2004   2005
             
Asset retirement obligation — beginning of period
   $ —     $ 155,284     $ 204,448  
Liabilities assumed upon donation of properties
     155,284       66,550       —  
Liabilities settled during the period
     —       —       (4,568 )
Current period accretion
     —       6,211       9,950  
Current period revisions to accretion expense
     —       (18,959 )     (6,600 )
Current period revisions to oil and natural gas properties
     —       (4,638 )     594  
                   
Asset retirement obligation — end of period
   $ 155,284     $ 204,448     $ 203,824  
                   
(7) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities
      Costs incurred by the Charitable Foundations in natural gas and oil property acquisition and development are presented below:
                   
    Year Ended
    December 31,
     
    2004   2005
         
Development costs
   $ 152,512     $ 146,719  
             
 
Total development costs
   $ 152,512     $ 146,719  
             
      Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas.
(8) Oil and Natural Gas Capitalized Costs
      Aggregate capitalized costs for the Charitable Foundations related to natural gas and oil production activities with applicable accumulated depreciation, depletion, and amortization are presented below:
                         
    December 31,
     
    2003   2004   2005
             
Proved oil and natural gas properties
   $ 3,138,684     $ 4,631,708     $ 4,774,454  
Accumulated depletion, depreciation and amortization
     —       (343,576 )     (632,670 )
                   
    $ 3,138,684     $ 4,288,132     $ 4,141,784  
                   

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
(9) Net Proved Oil and Natural Gas Reserves (Unaudited)
      The proved oil and natural gas reserves of the Charitable Foundations have been estimated by an independent petroleum engineer, LaRoche Petroleum Consultants, Ltd., as of December 31, 2003, 2004 and 2005. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules based on year-end prices. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, is shown below:
                     
    Oil and   Natural
    Condensate   Gas
    (MBbls)   (MMcf)
         
Total Proved Reserves
                
 
Balance, January 1, 2003
     —       —  
   
Donations of minerals-in-place
     231       762  
             
 
Balance, December 31, 2003
     231       762  
   
Donations of minerals-in-place
     99       326  
   
Extensions and discoveries
     13       53  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     7       3  
   
Revisions of previous estimates due to prices and performance
     48       2  
   
Production
     (26 )     (80 )
             
 
Balance, December 31, 2004
     372       1,066  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     87       115  
   
Revisions of previous estimates due to prices and performance
     25       82  
   
Production
     (27 )     (78 )
             
 
Balance, December 31, 2005
     457       1,185  
             
Proved Developed Reserves
                
 
December 31, 2003
     231       762  
 
December 31, 2004
     372       1,066  
 
December 31, 2005
     377       1,076  
(10) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves (Unaudited)
      Summarized in the following table is information for the Charitable Foundations with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Future cash inflows are computed by applying year-end prices relating to the Charitable Foundations’ proved reserves to the year-end quantities of those reserves. Future production, development, site restoration, and abandonment costs are

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Charitable Foundations are nontaxable entities.
                           
    December 31,
     
    2003   2004   2005
             
    (Thousands)
Future cash flows
   $ 10,828     $ 20,622     $ 36,354  
Future costs:
                        
 
Production
     (4,933 )     (9,170 )     (14,182 )
 
Development
     —       (20 )     (1,442 )
                   
Future net cash flows before income taxes
     5,895       11,432       20,730  
10% annual discount for estimated timing of cash flows
     (3,010 )     (5,878 )     (11,392 )
                   
Standardized measure of discounted net cash flows
   $ 2,885     $ 5,554     $ 9,338  
                   
      The Standardized Measure is based on the following oil and natural gas prices realized over the life of the properties at the wellhead as of the following dates:
                         
    December 31,
     
    2003   2004   2005
             
Oil (per Bbl)
   $ 29.35     $ 40.27     $ 56.69  
Natural gas (per MMBtu)
   $ 5.32     $ 5.28     $ 8.82  
      The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows:
                             
    Year Ended
    December 31,
     
    2003   2004   2005
             
    (Thousands)
Increase (decrease):
                        
 
Sales, net of production costs
   $ —     $ (955 )   $ (1,200 )
 
Net change in sales prices, net of production costs
     —       994       2,435  
 
Changes in estimated future development costs
     —       (10 )     (1,117 )
 
Extensions and discoveries, net of future production and development costs
     —       266       —  
 
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     —       95       2,057  
 
Previously estimated development costs incurred
     —       —       (20 )
 
Revisions of previous estimates due to prices and performance
     —       486       595  
 
Donations of minerals-in place
     2,885       1,225       —  
 
Other
     —       218       577  
 
Accretion of discount
     —       350       457  
                   
   
Net increase
     2,885       2,669       3,784  
Standardized measure of discounted future net cash flows:
                        
 
Beginning of year
     —       2,885       5,554  
                   
 
End of year
   $ 2,885     $ 5,554     $ 9,338  
                   

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SELECTED PROPERTIES OF CHARITIES SUPPORT FOUNDATION INC. AND AFFILIATES
NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)
      The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.
(11) Subsequent Event
      On March 15, 2006, Legacy Reserves LP (“Legacy”), the successor entity to the Moriah Group, completed a private equity offering (“Legacy Formation”) in which it issued 5,000,000 limited partnership units at a gross price of $17.00 per unit. Simultaneous with the completion of this offering, Legacy purchased the oil and natural gas properties of the Charitable Foundations solely for $7.7 million cash. The Moriah Group has been treated as the acquiring entity in the formation transaction of Legacy. Legacy was formed in October 2005.

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Report of Independent Registered Public Accounting Firm
MBN Properties, LP
Midland, Texas
      We have audited the accompanying statements of revenues and direct operating expenses of the oil and natural gas properties (the “PITCO Properties”), as defined in Note 1, acquired on September 14, 2005 by MBN Properties, LP (the Company) for each of the years in the three year period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The PITCO Properties are not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the PITCO Properties’ 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.
      The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 and are not intended to be a complete presentation of the results of operations of the PITCO Properties.
      In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the PITCO Properties for each of the years in the three year period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
  /s/ BDO Seidman, LLP
Houston, Texas
November 7, 2005

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PITCO PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES —
OIL AND NATURAL GAS PROPERTIES ACQUIRED FROM
THE PROSPECTIVE INVESTMENT AND TRADING COMPANY, LTD.
                                           
    Year Ended December 31,   Six Months Ended June 30,
         
    2002   2003   2004   2004   2005
                     
                (Unaudited)
Revenue — Oil and natural gas sales
   $ 7,732,266     $ 10,524,858     $ 12,832,660     $ 5,715,561     $ 6,515,477  
                               
Direct Operating Expenses:
                                        
 
Production and other taxes
     722,847       904,555       1,112,708       426,486       473,391  
 
Lease operating expenses
     1,873,833       2,088,465       2,567,721       1,329,024       1,062,944  
 
Well workover expenses
     526,040       672,098       529,644       265,854       305,908  
                               
Total direct operating expenses
     3,122,720       3,665,118       4,210,073       2,021,364       1,842,243  
                               
Revenue in excess of direct operating expenses
   $ 4,609,546     $ 6,859,740     $ 8,622,587     $ 3,694,197     $ 4,673,234  
                               
See accompanying notes to statements of revenue and direct operating expenses.

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PITCO PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(1) Basis of Presentation
      The accompanying financial statements present the revenues and direct operating expenses of the oil and natural gas properties (the “PITCO Properties”) acquired by MBN Properties LP (the “Company”) from The Prospective Investment and Trading Company, LTD., PITCO Investments, LTD., JAG Oil Limited Partnership, AS IS Investments, L.L.C., and High Hopes Oil Company, L.L.C., collectively, “PITCO,” for the period January 1, 2002 through June 30, 2005. The PITCO Properties were purchased by the Company on September 14, 2005, for $66,151,723, subject to post-closing adjustments. The PITCO Properties consist of working interests, net profits interests, and royalty interests primarily located in the Permian Basin of West Texas and southeast New Mexico.
      The accompanying statements of revenues and direct operating expenses of the Properties do not include indirect general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes. Management of the Company believes historical expenses of this nature incurred by PITCO and its affiliates are not indicative of the costs to be incurred by the Company.
      Revenues in the accompanying statements of revenues and direct operating expenses are recognized based on PITCO’s share of any given period’s production multiplied times the contract price received for the period. The direct operating expenses are recognized on the accrual basis and consist of the direct costs of operating the PITCO Properties including production and other taxes, lifting costs, gathering, well repair and well workover costs. Direct costs also include contractual overhead charged to properties operated by others, but does not include general corporate overhead.
      Historical financial information reflecting financial position, results of operations, and cash flows of the Properties is not presented because it would be impractical and costly to obtain since such financial information was not historically prepared by PITCO. Other assets acquired and liabilities assumed were not material. In addition, the PITCO Properties were a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of indirect general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the PITCO Properties acquired, nor would such allocated historical costs be relevant to future operations of the PITCO Properties. The historical statements of revenues and direct operating expenses of PITCO’s interest in the PITCO Properties are presented in order to substantially comply with the rules and regulations of the Securities and Exchange Commission for businesses acquired.
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
      The statements of revenues and direct operating expenses of the PITCO Properties for the six months ended June 30, 2004 and 2005 are unaudited. In the opinion of the company’s management, such statements include the adjustments and accruals which are necessary for a fair presentation of results for the Properties. These interim results are not necessarily indicative of results for a full year.
(2) Supplemental Financial Information for Oil and Natural Gas Producing Activities (Unaudited)
      The following reserve estimates have been prepared by an independent petroleum engineering firm, LaRoche Petroleum Consultants, Ltd., as of December 31, 2002, 2003, 2004. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules based on year-end prices for oil and natural gas with appropriate adjustments by property for location, quality, gathering and marketing adjustments.

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PITCO PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
     (a) Reserve Quantity Information
      Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods.
      Below are the net quantities of net total proved reserves, and net proved developed reserves of the Properties. An analysis of the change in estimated quantities of reserves, all of which are located within the United States, is presented below.
                     
    Oil   Natural Gas
    (MBbl)   (MMcf)
         
PROVED RESERVES:
                
 
Balance, December 31, 2001
     1,480       9,236  
   
Revisions of previous estimates
     622       1,688  
   
Production
     (187 )     (1,114 )
             
 
Balance, December 31, 2002
     1,915       9,810  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     290       —  
   
Revisions of previous estimates due to prices and performance
     92       932  
   
Production
     (187 )     (1,062 )
             
 
Balance, December 31, 2003
     2,110       9,680  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     375       —  
   
Revisions of previous estimates due to prices and performance
     265       122  
   
Production
     (192 )     (992 )
             
 
Balance, December 31, 2004
     2,558       8,810  
             
PROVED DEVELOPED RESERVES:
                
 
December 31, 2001
     1,480       9,236  
 
December 31, 2002
     1,915       9,810  
 
December 31, 2003
     2,110       9,680  
 
December 31, 2004
     2,256       8,810  
     (b) Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and Natural Gas Reserves
      The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is a disclosure requirement under Statement of Financial Accounting Standards No. 69. The standardized measure does not purport to be, nor should it be interpreted to present, the fair market value of the proved oil and natural gas reserves of the Properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs are based on period-end sales prices for oil and natural gas, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are

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PITCO PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
then discounted at a rate of 10%. No deduction has been made for general and administrative expenses, interest expense, depreciation, depletion and amortization or for federal or state income taxes.
      The standardized measure (before income taxes) relating to proved oil and natural gas reserves are presented below (in thousands):
                         
    December 31,
     
    2002   2003   2004
             
Future cash inflows
   $ 97,486     $ 116,802     $ 152,761  
Future production costs
     (36,971 )     (44,396 )     (58,861 )
Future development costs
     —       —       (727 )
                   
Future net cash flows
     60,515       72,406       93,173  
10% annual discount for estimated timing of cash flows
     (27,243 )     (34,411 )     (46,942 )
                   
Standardized measure of discounted net cash flows
   $ 33,272     $ 37,995     $ 46,231  
                   
      The standardized measure is based on the following oil and natural gas price realized over the life of the properties at the wellhead as of the following dates:
                         
    December 31,
     
    2002   2003   2004
             
Oil (per Bbl)
   $ 29.14     $ 30.23     $ 40.99  
Natural gas (per MMBtu)
   $ 4.23     $ 5.46     $ 5.42  
      Changes in the Standardized Measure (before income taxes) relating to proved oil and natural gas reserves is as follows (in thousands):
                             
    Year Ended December 31,
     
    2002   2003   2004
             
Increase (Decrease):
                        
 
Sales, net or production costs
   $ (4,610 )   $ (6,860 )   $ (8,623 )
 
Net change in prices and production costs
     11,423       4,014       6,470  
 
Net change in future development costs
     —       —       (686 )
 
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     —       2,135       3,820  
 
Revisions of previous estimates due to prices and performance
     8,464       2,521       3,310  
 
Accretion of discount
     1,488       3,117       3,565  
 
Changes in timing of production and other
     288       (204 )     380  
                   
 
Net increase
     17,053       4,723       8,236  
 
Standardized measure of discounted net cash flows:
                        
   
Beginning of year
     16,219       33,272       37,995  
                   
   
End of year
   $ 33,272     $ 37,995     $ 46,231  
                   
      Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree speculative and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations, reservoir behavior, equipment condition and other matters. Actual quantities of oil and natural gas produced in the future may differ materially from the amounts estimated.

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Report of Independent Registered Public Accounting Firm
Legacy Reserves, LP
Midland, Texas
      We have audited the accompanying statements of revenues, operating fees and operating expenses of the oil and natural gas properties (the “South Justis Properties”), as defined in Note 1, acquired on June 29, 2006 by Legacy Reserves LP (the Company) for each of the years in the two year period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The South Justis Properties are not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the South Justis Properties’ 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.
      The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 and are not intended to be a complete presentation of the results of operations of the South Justis Properties.
      In our opinion, the statements of revenues, operating fees and operating expenses referred to above present fairly, in all material respects, the revenues, operating fees and operating expenses of the South Justis Properties for each of the years in the two year period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
      As discussed in Note 1, the statements of revenues, operating fees and operating expenses referred to above have been restated to include operating fees in the measure of revenue and operating fees in excess of operating expenses and to include an allocation of the seller’s general and administrative expenses.
Houston, Texas
October 2, 2006
  /s/ BDO Siedman, LLP

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SOUTH JUSTIS PROPERTIES
STATEMENTS OF REVENUES, OPERATING FEES AND OPERATING EXPENSES —
OIL AND NATURAL GAS PROPERTIES ACQUIRED FROM HENRY HOLDING LP
                                   
    Year Ended December 31,   Six Months Ended June 30,
         
    2004   2005   2005   2006
                 
    Restated   Restated   Restated   Restated
            (Unaudited)
Revenue — Oil and natural gas sales
   $ 1,829,385     $ 2,408,628     $ 1,076,549     $ 1,313,931  
Operating expenses and operating fees:
                                
 
Production and other taxes
     154,907       197,510       88,303       109,948  
 
Lease operating expenses
     389,242       560,883       249,635       311,809  
 
Operating fees (Note 1)
     (1,452,737 )     (1,642,272 )     (806,085 )     (857,840 )
 
General and administrative expenses
     613,866       819,719       408,598       463,495  
                         
Operating expenses in excess of (less than) operating fees
     (294,722 )     (64,160 )     (59,549 )     27,412  
                         
Revenue and operating fees in excess of operating expenses
   $ 2,124,107     $ 2,472,788     $ 1,136,098     $ 1,286,519  
                         
See accompanying notes to statements of revenue, operating fees and operating expenses.

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SOUTH JUSTIS PROPERTIES
NOTES TO STATEMENTS OF REVENUES, OPERATING FEES AND OPERATING EXPENSES
(1) Basis of Presentation
      The accompanying financial statements present the revenues, operating fees and operating expenses of the oil and natural gas properties (the “South Justis Properties” or “Properties”) acquired by Legacy Reserves Operating LP (the “Company”), the wholly owned subsidiary of Legacy Reserves LP, from Henry Holding LP (“Henry”), for the period January 1, 2004 through June 30, 2006. The South Justis Properties were purchased by the Company on June 29, 2006, for the stated price of $14,000,000 cash and 138,000 units issued June 29, 2006 and 8,415 units issued November 10, 2006 of Legacy Reserves LP less final adjustments of approximately $624,000. The South Justis Properties consist primarily of a 15.0% working interest and 13.1% net revenue interest in the South Justis Unit located in southeast New Mexico.
      The accompanying statements of revenues, operating fees and operating expenses of the Properties have been restated to include operating fees in the measure of revenue and operating fees in excess of operating expenses (such fees were previously presented separately) and to include an allocation of Henry’s general and administrative expenses related primarily to salaries and benefits of employees providing support services directly to the Properties and other general and administrative expenses. These expenses were allocated to the properties on a proportionate per-well basis, which was considered to be a reasonable allocation method by Henry’s management. Management of the Company believes historical expenses of this nature incurred by Henry and its affiliates are not necessarily indicative of the costs to be incurred by the Company. The accompanying statements of revenues, operating fees and operating expenses do not include interest expense, depreciation, depletion and amortization related to Henry’s cost basis of the oil and natural gas properties, or any provision for income taxes.
      The following table provides a reconciliation of those financial statement line items affected by the restatement:
                                 
    Year Ended December 31,   Six Months Ended June 30,
         
    2004   2005   2005   2006
                 
Total direct operating expenses — as originally reported
   $ 544,149     $ 758,393     $ 337,938     $ 421,757  
Operating fees — reported as a separate caption originally
     (1,452,737 )     (1,642,272 )     (806,085 )     (857,840 )
General and administrative expenses — not reported originally
     613,866       819,719       408,598       463,495  
                         
Operating expenses in excess of (less than) operating fees — this item has been renamed in the restatement
   $ (294,722 )   $ (64,160 )   $ (59,549 )   $ 27,412  
                         
Revenue in excess of direct operating expenses — as reported originally
   $ 1,285,236     $ 1,650,235     $ 738,611     $ 892,174  
Operating fees — reported as separate caption originally
     1,452,737       1,642,272       806,085       857,840  
General and administrative expenses — not reported originally
     (613,866 )     (819,719 )     (408,598 )     (463,495 )
                         
Revenues and operating fees in excess of operating expenses — this item has been renamed in the restatement
   $ 2,124,107     $ 2,472,788     $ 1,136,098     $ 1,286,519  
                         

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SOUTH JUSTIS PROPERTIES
NOTES TO STATEMENTS OF REVENUES, OPERATING FEES AND
OPERATING EXPENSES — (Continued)
      Revenues in the accompanying statements of revenues, operating fees and operating expenses are recognized based on the South Justis’ Properties share of any given period’s production multiplied times the contract price received for the period. Operating expenses are recognized on the accrual basis and include the direct costs of operating the South Justis Properties, including production taxes, lifting costs, gathering, well repair and well workover costs, as well as the allocated general and administrative expenses noted above. Operating fees represent fees received by Henry from the third party owners of the acquired properties for operations and engineering management, regulatory reporting and accounting services.
      Historical financial information reflecting financial position, results of operations, and cash flows of the Properties is not presented because it would be impractical and costly to obtain such financial information and since it was not historically prepared by Henry. Other assets acquired and liabilities assumed were not material. The historical statements of revenues, operating fees and operating expenses of Henry’s interest in the South Justis Properties are presented in order to substantially comply with the rules and regulations of the Securities and Exchange Commission for businesses acquired.
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
      The statements of revenues, operating fees and operating expenses of the Properties for the six months ended June 30, 2005 and 2006 are unaudited. In the opinion of the Company’s management, such statements include the adjustments and accruals which are necessary for a fair presentation of results for the Properties. These interim results are not necessarily indicative of results for a full year.
(2) Supplemental Financial Information for Oil and Natural Gas Producing Activities (Unaudited)
      The following reserve estimates have been prepared by an independent petroleum engineering firm, LaRoche Petroleum Consultants, Ltd., as of December 31, 2003, 2004 and 2005. These reserve estimates have been prepared in compliance with the Securities and Exchange Commission rules based on year-end prices for oil and natural gas with appropriate adjustments by property for location, quality, gathering and marketing adjustments.
     (a) Reserve Quantity Information
      Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods.

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SOUTH JUSTIS PROPERTIES
NOTES TO STATEMENTS OF REVENUES, OPERATING FEES AND
OPERATING EXPENSES — (Continued)
      Below are the net quantities of net total proved reserves, and net proved developed reserves of the Properties. An analysis of the change in estimated quantities of reserves, all of which are located within the United States, is presented below.
                     
    Oil   Natural Gas
    (MBbl)   (MMcf)
         
PROVED RESERVES:
                
 
Balance, December 31, 2003
     399       785  
   
Revisions of previous estimates due to prices and performance
     27       50  
   
Production
     (35 )     (84 )
             
 
Balance, December 31, 2004
     391       751  
   
Revisions of previous estimates due to prices and performance
     1       31  
   
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     180       368  
   
Production
     (34 )     (71 )
             
 
Balance, December 31, 2005
     538       1,079  
             
PROVED DEVELOPED RESERVES:
                
 
December 31, 2003
     399       785  
 
December 31, 2004
     391       751  
 
December 31, 2005
     464       953  
     (b) Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and Natural Gas Reserves
      The standardized measure of discounted future net cash flows relating to proved oil and gas reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standards No. 69. The standardized measure does not purport to be, nor should it be interpreted to present, the fair market value of the proved oil and natural gas reserves of the Properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs are based on period-end sales prices for oil and natural gas, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%. No deduction has been made for general and administrative expenses, interest expense, depreciation, depletion and amortization or for federal or state income taxes.

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SOUTH JUSTIS PROPERTIES
NOTES TO STATEMENTS OF REVENUES, OPERATING FEES AND
OPERATING EXPENSES — (Continued)
      The standardized measure (before income taxes) relating to proved oil and natural gas reserves are presented below (in thousands):
                 
    December 31,
     
    2004   2005
         
Future cash inflows
   $ 20,239     $ 41,748  
Future production costs
     (11,147 )     (18,323 )
Future development costs
     (49 )     (2,798 )
             
Future net cash flows
     9,043       20,627  
10% annual discount for estimated timing of cash flows
     (3,553 )     (9,639 )
             
 
Standardized measure of discounted net cash flows
   $ 5,490     $ 10,988  
             
      The standardized measure is based on the following oil and natural gas price realized over the life of the properties at the wellhead as of the following dates:
                 
    December 31,
     
    2004   2005
         
Oil (per Bbl)
   $ 39.91     $ 57.42  
Natural gas (per MMBtu)
   $ 6.18     $ 10.08  
      Changes in the standardized measure (before income taxes) relating to proved oil and natural gas reserves is as follows (in thousands):
                 
    Year Ended
    December 31,
     
    2004   2005
         
Increase (Decrease):
                
Sales of oil and natural gas, net of production costs
   $ (1,285 )   $ (1,650 )
Net change in prices and production costs
     1,323       3,730  
Revisions of previous estimates due to infill drilling, recompletions and stimulations
     —       3,713  
Revisions of previous estimates due to prices and performance
     386       104  
Accretion of discount
     378       381  
Changes in timing of production and other
     349       (780 )
             
Net increase
     1,151       5,498  
Standardized measure of discounted net cash flows:
                
Beginning of year
     4,339       5,490  
             
End of year
   $ 5,490     $ 10,988  
             
      Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree speculative and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations, reservoir behavior, equipment condition and other matters. Actual quantities of oil and natural gas produced in the future may differ materially from the amounts estimated.

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Report of Independent Registered Public Accounting Firm
Legacy Reserves, LP
Midland, Texas
      We have audited the accompanying statements of revenues and direct operating expenses of the oil and natural gas properties (the “Kinder Morgan Properties”), as defined in Note 1, acquired on July 31, 2006 by Legacy Reserves LP (the Company) for each of the years in the two year period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Kinder Morgan Properties are not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Kinder Morgan Properties’ 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.
      The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 and are not intended to be a complete presentation of the results of the Kinder Morgan Properties.
      In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Kinder Morgan Properties for each of the years in the two year period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
  /s/ BDO Siedman, LLP
Houston, Texas
July 14, 2006

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KINDER MORGAN PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES —
OIL AND NATURAL GAS PROPERTIES ACQUIRED FROM
KINDER MORGAN PRODUCTION COMPANY LP
                                   
    Year Ended December 31,   Six Months Ended June 30,
         
    2004   2005   2005   2006
                 
            (Unaudited)
Revenue — Oil and natural gas sales
   $ 5,068,501     $ 6,509,522     $ 3,045,198     $ 3,601,903  
Direct Operating Expenses:
                                
 
Production and other taxes
     385,869       497,737       191,608       277,011  
 
Lease operating expenses
     1,744,062       2,037,917       918,700       1,166,315  
                         
Total direct operating expenses
     2,129,931       2,535,654       1,110,308       1,443,326  
                         
Revenue in excess of direct operating expenses
   $ 2,938,570     $ 3,973,868     $ 1,934,890     $ 2,158,577  
                         
See accompanying notes to statements of revenue and direct operating expenses.

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KINDER MORGAN PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(1) Basis of Presentation
      The accompanying financial statements present the revenues and direct operating expenses of the oil and natural gas properties (the “Kinder Morgan Properties”) acquired by Legacy Reserves Operating LP (the “Company”), the wholly owned subsidiary of Legacy Reserves LP, from Kinder Morgan Production Company LP (“Kinder Morgan”), for the period January 1, 2004 through June 30, 2006. The Kinder Morgan Properties were purchased by the Company on July 31, 2006, for $19,700,000 cash. The assets acquired included properties in the Destino Field, which the Company sold to a third party on July 31, 2006 for $2,200,000. The accompanying financial statements present the revenues and direct operating expenses for only those oil and natural gas properties retained by Legacy. The net purchase price was $17,500,000 prior to post closing adjustments to be made within 90 days of closing. The Kinder Morgan Properties consist primarily of working interests and royalty interests in 85 producing wells and 44 water injection wells located in 9 fields in Texas and southeast New Mexico, in which over 90% of the net production is operated.
      The accompanying statements of revenues and direct operating expenses of the Properties do not include indirect general and administrative expenses, interest expense, depreciation, depletion and amortization, or any provision for income taxes. Management of the Company believes historical expenses of this nature incurred by Kinder Morgan and its predecessors in interest in the properties are not indicative of the costs to be incurred by the Company.
      Revenues in the accompanying statements of revenues and direct operating expenses are recognized based on Kinder Morgan Properties’ share of any given period’s production multiplied times the contract price received for the period. The direct operating expenses are recognized on the accrual basis and consist of the direct costs of operating the Kinder Morgan Properties including production taxes, lifting costs, gathering, well repair and well workover costs. Direct costs also include administrative overhead fees charged by third party operators in which the Company owns an interest, but does not include general corporate overhead.
      Historical financial information reflecting financial position, results of operations, and cash flows of the Properties is not presented because it would be impractical and costly to obtain since such financial information was not historically prepared by Kinder Morgan and its predecessors in interest in the properties. Other assets acquired and liabilities assumed were not material. In addition, the Kinder Morgan Properties were a part of a larger enterprise prior to the acquisition by the Company, and representative amounts of indirect general and administrative expenses, depreciation, depletion and amortization, interest and other indirect costs were not necessarily allocated to the Kinder Morgan Properties acquired, nor would such allocated historical costs be relevant to future operations of the Kinder Morgan Properties. The historical statements of revenues and direct operating expenses of Kinder Morgan’s interest in the Kinder Morgan Properties are presented in order to substantially comply with the rules and regulations of the Securities and Exchange Commission for businesses acquired.
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
      The statements of revenues and direct operating expenses of the Kinder Morgan Properties for the six months ended June 30, 2005 and 2006 are unaudited. In the opinion of the company’s management, such statements include the adjustments and accruals which are necessary for a fair presentation of results for the Properties. These interim results are not necessarily indicative of results for a full year.
(2) Supplemental Financial Information for Oil and Natural Gas Producing Activities (Unaudited)
      The following reserve estimates have been prepared by an independent petroleum engineering firm, LaRoche Petroleum Consultants, Ltd., as of December 31, 2003, 2004 and 2005. These reserve estimates have

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KINDER MORGAN PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
been prepared in compliance with the Securities and Exchange Commission rules based on year-end prices for oil and natural gas with appropriate adjustments by property for location, quality, gathering and marketing adjustments.
     (a) Reserve Quantity Information
      Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods.
      Below are the net quantities of net total proved reserves, and net proved developed reserves of the Properties. An analysis of the change in estimated quantities of reserves, all of which are located within the United States, is presented below.
                     
    Oil   Natural Gas
    (MBbl)   (MMcf)
         
PROVED RESERVES:
                
 
Balance, December 31, 2003
     859       305  
   
Revisions of previous estimates due to prices and performance
     260       141  
   
Production
     (124 )     (50 )
             
 
Balance, December 31, 2004
     995       396  
   
Revisions of previous estimates due to prices and performance
     353       196  
   
Production
     (117 )     (47 )
             
 
Balance, December 31, 2005
     1,231       545  
             
PROVED DEVELOPED RESERVES:
                
 
December 31, 2003
     859       305  
 
December 31, 2004
     995       396  
 
December 31, 2005
     1,231       545  
     (b) Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and Natural Gas Reserves
      The standardized measure of discounted future net cash flows relating to proved oil and gas reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standards No. 69. The standardized measure does not purport to be, nor should it be interpreted to present, the fair market value of the proved oil and natural gas reserves of the Properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs are based on period-end sales prices for oil and natural gas, estimated future production of proved reserves and estimated future production and development costs of proved reserves, based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%. No deduction has been made for general and administrative expenses, interest expense, depreciation, depletion and amortization or for federal or state income taxes.

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KINDER MORGAN PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
      The standardized measure (before income taxes) relating to proved oil and natural gas reserves are presented below (in thousands):
                 
    December 31,
     
    2004   2005
         
Future cash inflows
   $ 41,688     $ 74,618  
Future production costs
     (23,618 )     (38,082 )
Future development costs
     —       —  
             
Future net cash flows
     18,070       36,536  
10% annual discount for estimated timing of cash flows
     (7,628 )     (16,906 )
             
Standardized measure of discounted net cash flows
   $ 10,442     $ 19,630  
             
      The standardized measure is based on the following oil and natural gas price realized over the life of the properties at the wellhead as of the following dates:
                 
    December 31,
     
    2004   2005
         
Oil (per Bbl)
   $ 40.83     $ 58.61  
Natural gas (per MMBtu)
   $ 2.68     $ 4.55  
      Changes in the standardized measure (before income taxes) relating to proved oil and natural gas reserves is as follows (in thousands):
                 
    Year Ended
    December 31,
     
    2004   2005
         
Increase (Decrease):
                
Sales of oil and natural gas, net of production costs
   $ (2,939 )   $ (3,974 )
Net change in prices and production costs
     2,360       5,335  
Revisions of previous estimates due to prices and performance
     2,795       5,718  
Accretion of discount
     527       898  
Changes in timing of production and other
     1,165       1,211  
             
Net increase
     3,908       9,188  
             
Standardized measure of discounted net cash flows:
                
Beginning of year
     6,534       10,442  
             
End of year
   $ 10,442     $ 19,630  
             
      Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree speculative and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations, reservoir behavior, equipment condition and other matters. Actual quantities of oil and natural gas produced in the future may differ materially from the amounts estimated.

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APPENDIX A
AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP
OF
LEGACY RESERVES LP

Table of Contents

TABLE OF CONTENTS
                 
ARTICLE I

Definitions
  Section 1.1     Definitions     A-1  
  Section 1.2     Construction     A-10  
 
ARTICLE II

Organization
  Section 2.1     Formation     A-10  
  Section 2.2     Name     A-11  
  Section 2.3     Registered Office; Registered Agent; Principal Office; Other Offices     A-11  
  Section 2.4     Purpose and Business     A-11  
  Section 2.5     Powers     A-11  
  Section 2.6     Power of Attorney     A-11  
  Section 2.7     Term     A-12  
  Section 2.8     Title to Partnership Assets     A-13  
 
ARTICLE III

Rights of Limited Partners
  Section 3.1     Limitation of Liability     A-13  
  Section 3.2     Management of Business     A-13  
  Section 3.3     Outside Activities of the Limited Partners     A-13  
  Section 3.4     Rights of Limited Partners     A-13  
 
ARTICLE IV

Certificates; Record Holders; Transfer of
Partnership Interests; Redemption of Partnership Interests
  Section 4.1     Certificates     A-14  
  Section 4.2     Mutilated, Destroyed, Lost or Stolen Certificates     A-14  
  Section 4.3     Record Holders     A-15  
  Section 4.4     Transfer Generally     A-15  
  Section 4.5     Registration and Transfer of Limited Partner Interests     A-16  
  Section 4.6     Transfer of the General Partner’s General Partner Interest     A-16  
  Section 4.7     [Reserved]     A-17  
  Section 4.8     Restrictions on Transfers     A-17  
  Section 4.9     Citizenship Certificates; Non-citizen Assignees     A-17  
  Section 4.10     Redemption of Partnership Interests of Non-citizen Assignees     A-18  
 
ARTICLE V

Capital Contributions and
Issuance of Partnership Interests
  Section 5.1     Organizational Contributions     A-19  
  Section 5.2     Contributions by the General Partner     A-19  
  Section 5.3     Contributions by Founding Investors and the Initial Purchaser and Accredited Investors     A-19  
  Section 5.4     Interest and Withdrawal     A-20  
  Section 5.5     Capital Accounts     A-20  

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  Section 5.6     Issuances of Additional Partnership Securities     A-22  
  Section 5.7     [Reserved]     A-22  
  Section 5.8     Limited Preemptive Right     A-23  
  Section 5.9     Splits and Combinations     A-23  
  Section 5.10     Fully Paid and Non-Assessable Nature of Limited Partner Interests     A-23  
 
ARTICLE VI

Allocations and Distributions
  Section 6.1     Allocations for Capital Account Purposes     A-23  
  Section 6.2     Allocations for Tax Purposes     A-26  
  Section 6.3     Requirement and Characterization of Distributions; Distributions to Record Holders     A-29  
 
ARTICLE VII

Management and Operation of Business
  Section 7.1     Management     A-29  
  Section 7.2     Certificate of Limited Partnership     A-31  
  Section 7.3     Restrictions on the General Partner’s Authority     A-31  
  Section 7.4     Reimbursement of the General Partner     A-32  
  Section 7.5     Outside Activities     A-32  
  Section 7.6     Loans from the General Partner; Loans or Contributions from the Partnership or Group Members     A-33  
  Section 7.7     Indemnification     A-33  
  Section 7.8     Liability of Indemnitees     A-35  
  Section 7.9     Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties     A-35  
  Section 7.10     Other Matters Concerning the General Partner     A-36  
  Section 7.11     Purchase or Sale of Partnership Securities     A-37  
  Section 7.12     [Reserved]     A-37  
  Section 7.13     Reliance by Third Parties     A-37  
 
ARTICLE VIII

Books, Records, Accounting and Reports
  Section 8.1     Records and Accounting     A-38  
  Section 8.2     Fiscal Year     A-38  
  Section 8.3     Reports     A-38  
 
ARTICLE IX

Tax Matters
  Section 9.1     Tax Returns and Information     A-38  
  Section 9.2     Tax Elections     A-38  
  Section 9.3     Tax Controversies     A-39  
  Section 9.4     Withholding     A-39  
 
ARTICLE X

Admission of Partners
  Section 10.1     Admission of Founding Investors and Initial Limited Partners     A-39  
  Section 10.2     Admission of Limited Partners     A-39  

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  Section 10.3     Admission of Successor General Partner     A-40  
  Section 10.4     Amendment of Agreement and Certificate of Limited Partnership     A-40  
 
ARTICLE XI

Withdrawal or Removal of Partners
  Section 11.1     Withdrawal of the General Partner     A-40  
  Section 11.2     Removal of the General Partner     A-41  
  Section 11.3     Interest of Departing General Partner and Successor General Partner     A-42  
  Section 11.4     [Reserved]     A-43  
  Section 11.5     Withdrawal of Limited Partners     A-43  
 
ARTICLE XII

Dissolution and Liquidation
  Section 12.1     Dissolution     A-43  
  Section 12.2     Continuation of the Business of the Partnership After Dissolution     A-44  
  Section 12.3     Liquidator     A-44  
  Section 12.4     Liquidation     A-44  
  Section 12.5     Cancellation of Certificate of Limited Partnership     A-45  
  Section 12.6     Return of Contributions     A-45  
  Section 12.7     Waiver of Partition     A-45  
  Section 12.8     Capital Account Restoration     A-45  
 
ARTICLE XIII

Amendment of Partnership
Agreement; Meetings; Record Date
  Section 13.1     Amendments to be Adopted Solely by the General Partner     A-46  
  Section 13.2     Amendment Procedures     A-47  
  Section 13.3     Amendment Requirements     A-47  
  Section 13.4     Meetings     A-48  
  Section 13.5     Notice of a Meeting     A-50  
  Section 13.6     Record Date     A-50  
  Section 13.7     Adjournment     A-50  
  Section 13.8     Waiver of Notice; Approval of Meeting; Approval of Minutes     A-50  
  Section 13.9     Quorum and Voting     A-50  
  Section 13.10     Conduct of a Meeting     A-51  
  Section 13.11     Action Without a Meeting     A-51  
  Section 13.12     Right to Vote and Related Matters     A-52  
 
ARTICLE XIV

Merger
  Section 14.1     Authority     A-52  
  Section 14.2     Procedure for Merger or Consolidation     A-52  
  Section 14.3     Approval by Limited Partners of Merger or Consolidation     A-53  
  Section 14.4     Certificate of Merger     A-54  
  Section 14.5     Amendment of Partnership Agreement     A-54  
  Section 14.6     Effect of Merger     A-54  

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ARTICLE XV

Right to Acquire Limited Partner Interests
  Section 15.1     Right to Acquire Limited Partner Interests     A-54  
 
ARTICLE XVI

General Provisions
  Section 16.1     Addresses and Notices     A-56  
  Section 16.2     Further Action     A-56  
  Section 16.3     Binding Effect     A-56  
  Section 16.4     Integration     A-56  
  Section 16.5     Creditors     A-57  
  Section 16.6     Waiver     A-57  
  Section 16.7     Third-Party Beneficiaries     A-57  
  Section 16.8     Counterparts     A-57  
  Section 16.9     Applicable Law     A-57  
  Section 16.10     Invalidity of Provisions     A-57  
  Section 16.11     Consent of Partners     A-57  
  Section 16.12     Facsimile Signatures     A-57  

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AMENDED AND RESTATED AGREEMENT OF
LIMITED PARTNERSHIP OF LEGACY RESERVES LP
      THIS AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF LEGACY RESERVES LP dated as of March 15, 2006, is entered into by and among Legacy Reserves GP, LLC, a Delaware limited liability company, as the General Partner, Moriah Properties Ltd., a Texas limited partnership, as the Organizational Limited Partner, and any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:
ARTICLE I
Definitions
Section 1.1     Definitions.
      The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.
      “Accredited Investor” shall have the meaning assigned to such term in Rule 501(a) promulgated under the Securities Act.
      “Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each fiscal year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such fiscal year are expected to be made to such Partner’s Capital Account in respect of the oil and gas properties of the Partnership (ii) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Partner in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii) and (iii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of a General Partner Interest, a Unit or any other specified interest in the Partnership shall be the amount that such Adjusted Capital Account would be if such General Partner Interest, Unit or any other specified interest in the Partnership were the only interest in the Partnership held by such Partner from and after the date on which such General Interest, Unit or other interest was first issued.
      “Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii).
      “Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.
      “Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including, without limitation, a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).
      “Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the General Partner. The General Partner shall use

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such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.
      “Agreement” means this Amended and Restated Agreement of Limited Partnership of Legacy Reserves LP, as it may be amended, supplemented or restated from time to time.
      “Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.
      “Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:
        (a) the sum of (i) all cash and cash equivalents of the Partnership Group on hand at the end of such Quarter and (ii) all additional cash and cash equivalents of the Partnership Group on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter, less
 
        (b) the amount of any cash reserves established by the General Partner to (i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures including drilling and acquisitions and for anticipated future credit needs of the Partnership Group), (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject or (iii) provide funds for distributions under Section 6.3 with respect to any one or more of the next four Quarters; provided, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.
      Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.
      “Board of Directors” means the board of directors or managers of a corporation or limited liability company, as applicable, or if a limited partnership, the board of directors or board of managers of the general partner of such limited partnership, as applicable.
      “Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.
      “Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.
      “Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of a General Partner Interest, a Unit or any other Partnership Interest shall be the amount that such Capital Account would be if such General Partner Interest, Unit or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Interest, Unit or other Partnership Interest was first issued.

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      “Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership.
      “Carrying Value” means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, Simulated Depletion, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.5(d)(i) and Section 5.5(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.
      “Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.
      “Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Units or (b) a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Securities.
      “Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.
      “Citizenship Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.
      “Closing Date” means the first date on which the Units are sold by the Partnership to the Initial Purchaser and the Accredited Investors pursuant to the provisions of the Purchase Agreement.
      “Closing Price” has the meaning assigned to such term in Section 15.1(a).
      “Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.
      “Combined Interest” has the meaning assigned to such term in Section 11.3(a).
      “Commission” means the United States Securities and Exchange Commission.
      “Conflicts Committee” means a committee of the Board of Directors of the General Partner composed entirely of two or more directors who are not (a) security holders, officers or employees of the General Partner, (b) officers, directors or employees of any Affiliate of the General Partner, (c) officers, directors or employees of any Group Member or (d) holders of any ownership interest in any Group Member other than Units and who also meet the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Units are or may be listed or admitted to trading.
      “Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.
      “Contribution Agreement” means that certain Contribution, Conveyance and Assumption Agreement, dated as of the Closing Date, among the General Partner, the Partnership, the Operating Partnership GP, the

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Operating Partnership and the other parties named therein, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.
      “Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(c)(ix).
      “Current Market Price” has the meaning assigned to such term in Section 15.1(a).
      “Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.
      “Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.
      “Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.
      “Director” means a member of the Board of Directors of the General Partner.
      “Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).
      “Eligible Citizen” means a Person whose status as a Limited Partner the General Partner determines does not or would not subject such Group Member to a significant risk of cancellation or forfeiture of any of its properties or any interest therein.
      “Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).
      “Founder Contributed Assets” means the assets to be contributed to the Partnership in exchange for Units as set forth in the Contribution Agreement.
      “Founders Registration Rights Agreement” means that certain Founders Registration Rights Agreement, dated as of the Closing Date, among the General Partner, the Partnership and the other parties named therein, as such may be amended, supplemented or restated from time to time.
      “Founding Investors” means (i) the natural persons that are the direct or indirect beneficial owners as of the Closing Date of the Persons referred to in the Contribution Agreement as “Contributing Parties”, (ii) any family members (including spouses) of any Persons described in clause (i), and (iii) any Affiliates of the Persons described in clauses (i) or (ii), including the Contributing Parties as of the Closing Date, but only for such time as they remain so affiliated.
      “General Partner” means Legacy Reserves GP, LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as a general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).
      “General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it) and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.
      “General Partner Unit” means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A General Partner Unit is not a Unit.
      “Group” means a Person that with or through any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

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      “Group Member” means a member of the Partnership Group.
      “Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.
      “Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any officer of the Partnership or any Subsidiary of the Partnership, (e) any Person who is or was a member, partner, director, officer, fiduciary or trustee of any Person that any of the preceding clauses of this definition describes, (f) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as an officer, director, member, partner, fiduciary or trustee of another Person, provided that that Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (g) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement.
      “Independent Director” means a Director meeting the independence and experience requirements as set forth in the rules of the principal National Securities Exchange on which the Units are traded.
      “Initial Limited Partners” means the Persons admitted to the Partnership in accordance with Section 10.1.
      “Initial Offering” means the initial offering and sale of Units to the Initial Purchaser and Accredited Investors, as described in the Offering Memorandum.
      “Initial Public Offering” means the closing of an initial offering and sale of Units to the public by the Partnership or any selling Unitholders pursuant to a Registration Statement generating aggregate gross proceeds to the Partnership and such selling Unitholders of not less than $20 million and following which the Units are listed or admitted to trading on a National Securities Exchange.
      “Initial Purchaser” means Friedman, Billings, Ramsey & Co., Inc. in its capacity as the initial purchaser of Units pursuant to the Purchase Agreement.
      “Issue Price” means the price at which a Unit is purchased from the Partnership, excluding the Initial Purchaser’s discount or any underwriting discount or placement fee charged to the Partnership.
      “Limited Partner” means, unless the context otherwise requires, the Organizational Limited Partner prior to its withdrawal from the Partnership, each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as a limited partner of the Partnership.
      “Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Units or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement.
      “Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

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      “Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.
      “Merger Agreement” has the meaning assigned to such term in Section 14.1.
      “National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor to such statute, or The Nasdaq Stock Market or any successor thereto.
      “Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.
      “Net Income” means, for any taxable year, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(c).
      “Net Loss” means, for any taxable year, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(c).
      “Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(c).
      “Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(c).
      “Non-citizen Assignee” means a Person whom the General Partner has determined does not constitute an Eligible Citizen and as to whose Partnership Interest the General Partner has become substituted as the Limited Partner pursuant to Section 4.9.
      “Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(c)(iii), Section 6.2(d)(i)(A), Section 6.2(d)(ii)(A) and Section 6.2(d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.
      “Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including, without limitation, any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or

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Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.
      “Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).
      “Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b).
      “Offering Memorandum” means the private placement memorandum dated March 6, 2006 relating to the private placement of Units of the Partnership.
      “Omnibus Agreement” means that Omnibus Agreement, dated as of the Closing Date, among the General Partner, the Partnership, the Operating Partnership GP, the Operating Partnership and the other parties thereto.
      “Operating Partnership Agreement” means the Limited Partnership Agreement of the Operating Partnership, as it may be amended, supplemented or restated from time to time.
      “Operating Partnership” means Legacy Reserves Operating LP, a Delaware limited partnership, and any successors thereto.
      “Operating Partnership GP Agreement” means the Limited Liability Company Agreement of the Operating Partnership GP, as it may be amended, supplemented or restated from time to time.
      “Operating Partnership GP” means Legacy Reserves Operating GP LLC, a Delaware limited liability company, and any successors thereto, in its capacity as general partner of the Operating Partnership.
      “Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.
      “Option Closing Date” means the date or dates on which any Units are sold by the Partnership to the Initial Purchaser upon exercise of the Over-Allotment Option.
      “Organizational Limited Partner” means Moriah Properties, Inc. in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.
      “Outstanding” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the Founding Investors) beneficially owns 20% or more of any Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly from the Founding Investors, (ii) any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the board of directors of the General Partner.
      “Over-Allotment Option” means the over-allotment option granted to the Initial Purchaser by the Partnership pursuant to the Purchase Agreement.
      “Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).
      “Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

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      “Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including, without limitation, any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.
      “Partners” means the General Partner and the Limited Partners.
      “Partnership” means Legacy Reserves LP, a Delaware limited partnership, and any successors thereto.
      “Partnership Group” means the Partnership and its Subsidiaries treated as a single consolidated entity.
      “Partnership Interest” means an ownership interest in the Partnership, which shall include the General Partner Interest and Limited Partner Interests.
      “Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).
      “Partnership Security” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to any equity interest in the Partnership), including Units.
      “Percentage Interest” means as of any date of determination (a) as to the General Partner with respect to the General Partner Interest and as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of all Outstanding Units, and (b) as to the holders of other Partnership Securities issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance.
      “Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization or other enterprise (including an employee benefit plan), association, governmental agency or political subdivision thereof or other entity.
      “Pro Rata” means (a) when modifying Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests and (b) when modifying Partners or Record Holders, apportioned among all Partners or Record Holders, as the case may be, in accordance with their relative Percentage Interests.
      “Purchase Agreement” means the Purchase/Placement Agreement dated March 6, 2006 among Freidman, Billings, Ramsey & Co., Inc., as the Initial Purchaser and the Placement Agent, the Partnership and the General Partner providing for the purchase of Units by the Initial Purchaser and the Accredited Investors.
      “Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.
      “Quarter” means, unless the context requires otherwise, a fiscal quarter, or, with respect to the first fiscal quarter after the Closing Date, the portion of such fiscal quarter after the Closing Date, of the Partnership.
      “Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.
      “Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing

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without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.
      “Record Holder” means the Person in whose name a Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.
      “Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.
      “Registration Rights Agreement” means that certain Registration Rights Agreement, dated as of the Closing Date, among the General Partner, the Partnership and Friedman, Billings, Ramsey & Co., Inc., as such may be amended, supplemented or restated from time to time.
      “Registration Statement” means a Registration Statement as it may be filed by the Partnership with the Commission under the Securities Act to register the offering and sale of Units in an Initial Public Offering.
      “Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(a)(ii)(B) and (C) and (b) any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(c)(i), Section 6.1(c)(ii), Section 6.1(c)(iii), Section 6.1(c)(vi) or Section 6.1(c)(viii).
      “Residual Gain” or “Residual Loss” means any item of gain or loss or Simulated Gain or Simulated Loss, as the case may be, of the Partnership recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain loss or Simulated Gain or Simulated Loss is not allocated pursuant to Section 6.2(d)(i)(A) or Section 6.2(d)(ii)(A), respectively, to eliminate Book-Tax Disparities.
      “Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.
      “Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).
      “Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property were its adjusted tax basis) and in the manner specified in Treasury Regulation § 1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.
      “Simulated Gain” means the excess of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.
      “Simulated Loss” means the excess of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.
      “Special Approval” means approval by a majority of the members of the Conflicts Committee.
      “Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a

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partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.
      “Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b).
      “Trading Day” has the meaning assigned to such term in Section 15.1(a).
      “Transfer” has the meaning assigned to such term in Section 4.4(a).
      “Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the General Partner to act as registrar and transfer agent for the Units; provided, that if no Transfer Agent is specifically designated for any other Partnership Securities, the General Partner shall act in such capacity.
      “Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Units in this Agreement, but shall not include General Partner Units (or General Partner Interests represented thereby).
      “Unitholders” means the holders of Units.
      “Unit Majority” means at least a majority of the Outstanding Units.
      “Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).
      “Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).
      “U.S. GAAP” means United States generally accepted accounting principles consistently applied.
      “Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).
      “Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Partners made pursuant to a credit facility or other arrangement to the extent such borrowings are required to be reduced to a relatively small amount each year (or for the year in which the Initial Offering is consummated, the 12-month period beginning on the Closing Date) for an economically meaningful period of time.
Section 1.2     Construction.
      Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; and (c) the term “include” or “includes” means includes, without limitation, and “including” means including, without limitation.
ARTICLE II
Organization
Section 2.1     Formation.
      The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the original Agreement of Limited Partnership of Legacy Reserves LP in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this

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Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes and a Partner has no interest in specific Partnership property.
Section 2.2     Name.
      The name of the Partnership shall be “Legacy Reserves LP”. The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “LP,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.
Section 2.3     Registered Office; Registered Agent; Principal Office; Other Offices.
      Unless and until changed by the General Partner, the registered office and registered agent of the Partnership in the State of Delaware shall be the initial registered office and registered agent named in the Certificate of Limited Partnership of the Partnership or such other place or agent as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be 303 W. Wall Street, Suite 1500, Midland, Texas 79701 or such other place as the General Partner may from time to time designate by notice to the Limited Partners.
Section 2.4     Purpose and Business.
      The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold or dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.
Section 2.5     Powers.
      The Partnership shall be empowered to do any and all acts and things necessary and appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.
Section 2.6     Power of Attorney.
      (a) Each Limited Partner hereby constitutes and appoints the General Partner and, if a Liquidator shall have been selected pursuant to Section 12.3, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the

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case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:
        (i) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, Article X, Article XI or Article XII; (E) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Partnership Securities issued pursuant to Section 5.6; and (F) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Partnership pursuant to Article XIV; and
 
        (ii) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to (A) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or (B) effectuate the terms or intent of this Agreement; provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.
Nothing contained in this Section 2.6(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.
      (b) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner and the transfer of all or any portion of such Limited Partner’s Partnership Interest and shall extend to such Limited Partner’s heirs, successors, assigns and personal representatives. Each such Limited Partner hereby agrees to be bound by any representation made by the General Partner or the Liquidator acting in good faith pursuant to such power of attorney; and each such Limited Partner, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in good faith under such power of attorney. Each Limited Partner shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator may request in order to effectuate this Agreement and the purposes of the Partnership.
Section 2.7     Term.
      The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

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Section 2.8     Title to Partnership Assets.
      Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer to the Partnership of record title to all Partnership assets held by the General Partner and its Affiliates, and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.
ARTICLE III
Rights of Limited Partners
Section 3.1     Limitation of Liability.
      The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.
Section 3.2     Management of Business.
      No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.
Section 3.3     Outside Activities of the Limited Partners.
      Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.
Section 3.4     Rights of Limited Partners.
      (a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand and at such Limited Partner’s own expense:
        (i) promptly after becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;

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        (ii) to obtain a current list of the name and last known business, residence or mailing address of each Partner;
 
        (iii) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and which each Partner has agreed to contribute in the future, and the date on which each became a Partner;
 
        (iv) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with a copy of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;
 
        (v) to obtain true and full information regarding the status of the business and financial condition of the Partnership Group; and
 
        (vi) to obtain such other information regarding the affairs of the Partnership as is just and reasonable.
      (b) Notwithstanding any other provision of this Agreement, the General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).
ARTICLE IV
Certificates; Record Holders; Transfer of
Partnership Interests; Redemption of Partnership Interests
Section 4.1     Certificates.
      Upon the Partnership’s issuance of Units to any Person, the Partnership shall issue, upon the request of such Person, one or more Certificates in the name of such Person evidencing the number of such Units being so issued. In addition, (a) upon the General Partner’s request, the Partnership shall issue to it one or more Certificates in the name of the General Partner evidencing its interests in the Partnership and (b) upon the request of any Person owning any other Partnership Securities, the Partnership shall issue to such Person one or more Certificates evidencing such Partnership Securities. Certificates shall be executed on behalf of the Partnership by the Chairman of the Board, President or any Executive Vice President or Vice President and the Chief Financial Officer or the Secretary or any Assistant Secretary of the General Partner. No Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the General Partner elects to issue Units in global form, the Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Units have been duly registered in accordance with the directions of the Partnership.
Section 4.2     Mutilated, Destroyed, Lost or Stolen Certificates.
      (a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Securities as the Certificate so surrendered.

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      (b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:
        (i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;
 
        (ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;
 
        (iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and
 
        (iv) satisfies any other reasonable requirements imposed by the General Partner.
      If a Limited Partner fails to notify the General Partner within a reasonable period of time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.
      (c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.
Section 4.3     Record Holders.
      The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Partnership Interest.
Section 4.4     Transfer Generally.
      (a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Interest to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.
      (b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void.

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      (c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner of any or all of the issued and outstanding equity interests of the General Partner.
Section 4.5     Registration and Transfer of Limited Partner Interests.
      (a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Units and transfers of such Units as herein provided. The Partnership shall not recognize transfers of Certificates evidencing Limited Partner Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.
      (b) Except as otherwise provided in Section 4.9, the General Partner shall not recognize any transfer of Limited Partner Interests until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.
      (c) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Partnership Interests shall be freely transferable.
Section 4.6     Transfer of the General Partner’s General Partner Interest.
      (a) Subject to Section 4.6(c), prior to March 31, 2016, the General Partner shall not transfer all or any part of its General Partner Interest to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Units (excluding any Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate (other than an individual) of the General Partner or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into another Person or the transfer by the General Partner of all or substantially all of its assets to another Person (other than an individual).
      (b) Subject to Section 4.6(c), on or after March 31, 2016, the General Partner may transfer all or any part of its General Partner Interest without Unitholder approval.
      (c) Notwithstanding anything contained in this Agreement to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person or replacement of the General Partner pursuant to Section 10.3 shall be permitted unless (i) the transferee or successor (as applicable) agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, including Section 13.4(c), (ii) the Partnership receives an Opinion of Counsel that such transfer or replacement would not result in the loss of limited liability of any Limited Partner or of any limited partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest of the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer or replacement pursuant to and in compliance

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with this Section 4.6, the transferee or successor (as applicable) shall, subject to compliance with the terms of Section 10.3, be admitted to the Partnership as a General Partner immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.
Section 4.7     [Reserved].
Section 4.8     Restrictions on Transfers.
      (a) Except as provided in Section 4.8(c), but notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).
      (b) The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.
      (c) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.
Section 4.9     Citizenship Certificates; Non-citizen Assignees.
      (a) If any Group Member is or becomes subject to any federal, state or local law or regulation that the General Partner determines would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Limited Partner, the General Partner may request any Limited Partner to furnish to the General Partner, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Limited Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such other Person) as the General Partner may request. If a Limited Partner fails to furnish to the General Partner within the aforementioned 30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the General Partner determines that a Limited Partner (or, if the Limited Partner is a nominee holding for the account of another Person, such other Person) is not an Eligible Citizen, the Partnership Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10. In addition, the General Partner may require that the status of any such Limited Partner be changed to that of a Non-citizen Assignee and, thereupon, the General Partner shall be substituted for such Non-citizen Assignee as the Limited Partner in respect of his Limited Partner Interests.
      (b) The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Non-citizen Assignees, distribute the votes in the same ratios as the votes of Partners (including the General Partner) in respect of Limited Partner Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter.
      (c) Upon dissolution of the Partnership, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Non-citizen Assignee’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by

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the Partnership from the Non-citizen Assignee of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).
      (d) At any time after he can and does certify that he has become an Eligible Citizen, a Non-citizen Assignee may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Non-citizen Assignee not redeemed pursuant to Section 4.10, such Non-citizen Assignee be admitted as a Limited Partner, and upon approval of the General Partner, such Non-citizen Assignee shall be admitted as a Limited Partner and shall no longer constitute a Non-citizen Assignee and the General Partner shall cease to be deemed to be the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests.
Section 4.10     Redemption of Partnership Interests of Non-citizen Assignees.
      (a) If at any time a Limited Partner fails to furnish a Citizenship Certification or other information requested within the 30-day period specified in Section 4.9(a), or if upon receipt of such Citizenship Certification or other information the General Partner determines, with the advice of counsel, that a Limited Partner is not an Eligible Citizen, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is an Eligible Citizen or has transferred his Partnership Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship Certification to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interests of such Limited Partner as follows:
        (i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.
 
        (ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Partnership Interests of the class to be so redeemed multiplied by the number of Partnership Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.
 
        (iii) Upon surrender by or on behalf of the Limited Partner, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Limited Partner or his duly authorized representative shall be entitled to receive the payment therefor.
 
        (iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Partnership Interests.
      (b) The provisions of this Section 4.10 shall also be applicable to Partnership Interests held by a Limited Partner as nominee of a Person determined to be other than an Eligible Citizen.
      (c) Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Partnership Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Partnership Interest certifies to the satisfaction of the General Partner that he is an Eligible Citizen. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

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ARTICLE V
Capital Contributions and
Issuance of Partnership Interests
Section 5.1     Organizational Contributions.
      In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $1, for a 0.1% General Partner Interest in the Partnership and has been admitted as the General Partner of the Partnership, and the Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $999 for a 99.9% Limited Partner Interest in the Partnership and has been admitted as a Limited Partner of the Partnership. As of the Closing Date, simultaneously with the admission of the Initial Limited Partners as limited partners of the Partnership, the interest of the Organizational Limited Partner shall be redeemed; and the initial Capital Contribution of the Organizational Limited Partner shall thereupon be refunded and the Organizational Limited Partner shall cease to be a limited partner of the Partnership. Ninety-nine and nine tenths percent of any interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated and distributed to the Organizational Limited Partner, and the balance thereof shall be allocated and distributed to the General Partner.
Section 5.2     Contributions by the General Partner.
      (a) On the Closing Date and pursuant to the Contribution Agreement, the General Partner shall contribute to the Partnership a 0.1% undivided interest in all of the Founder Contributed Assets in exchange for a number of General Partner Units constituting .1001% of the Units to be issued to the Limited Partners.
      (b) Upon the issuance of any additional Limited Partner Interests by the Partnership, the General Partner may, in exchange for a proportionate number of General Partner Units, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest by (B) 100 less the General Partner’s Percentage Interest times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests. Except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.
Section 5.3     Contributions by Founding Investors, the Initial Purchaser and Accredited Investors.
      (a) On the Closing Date and pursuant to the Contribution Agreement, Founding Investors shall contribute in the aggregate a 99.9% undivided interest in all of the Founder Contributed Assets. In exchange for such Capital Contributions by the Founding Investors, the Partnership shall issue Units to such Founding Investor in the amount set forth for such Founding Investor in the Contribution Agreement.
      (b) On the Closing Date and pursuant to the Purchase Agreement, the Initial Purchaser shall contribute to the Partnership cash in an amount equal to the Issue Price per Unit sold in the Initial Offering, multiplied by the number of Units specified in the Purchase Agreement to be purchased by the Initial Purchaser at the Closing Date. In exchange for such Capital Contribution by the Initial Purchaser, the Partnership shall issue Units to the Initial Purchaser in an amount equal to the quotient obtained by dividing (i) the cash contribution to the Partnership by the Initial Purchaser by (ii) the Issue Price per Unit sold in the Initial Offering. Upon the exercise of the Over-Allotment Option, the Initial Purchaser shall contribute to the Partnership cash in an amount equal to the Issue Price per Unit sold in the Initial Offering, multiplied by the number of Units to be purchased by the Initial Purchaser at the Option Closing Date. In exchange for such Capital Contribution by the Initial Purchaser, the Partnership shall issue Units to the Initial Purchaser in an amount equal to the quotient obtained by dividing (x) the cash contributions to the Partnership by the Initial Purchaser on the Option Closing Date by (y) the Issue Price per Unit sold in the Initial Offering.
      (c) On the Closing Date and pursuant to the Purchase Agreement, each Accredited Investor shall contribute to the Partnership cash in an amount equal to the Issue Price per Unit sold in the Initial Offering, multiplied by the number of Units specified in the Purchase Agreement to be purchased by such Accredited Investor at the Closing Date. In exchange for such Capital Contribution by each Accredited Investor, the

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Partnership shall issue Units to each Accredited Investor in an amount equal to the quotient obtained by dividing (i) the cash contribution to the Partnership by such Accredited Investor by (ii) the Issue Price per Unit sold in the Initial Offering. Upon the exercise of the Over-Allotment Option, each Accredited Investor shall contribute to the Partnership cash in an amount equal to the Issue Price per Unit sold in the Initial Offering, multiplied by the number of Units to be purchased by such Accredited Investor at the Option Date. In exchange for such Capital Contribution by each Accredited Investor, the Partnership shall issue Units to each Accredited Investor in an amount equal to the quotient obtained by dividing (x) the cash contributions to the Partnership by such Accredited Investor on the Option Closing Date by (y) the Issue Price per Unit sold in the Initial Offering.
      (d) No Partnership Interests will be issued or issuable as of or at the Closing Date other than (i) the Units issuable pursuant to Section 5.3(a), Section 5.3(b) and Section 5.3(c) in an aggregate number equal to 18,292,683 Units (after giving effect to the redemption of Units pursuant to the Initial Offering) and (ii) the Units to be issued or issuable under the Legacy Reserves LP Long-Term Incentive Plan.
Section 5.4     Interest and Withdrawal.
      No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.
Section 5.5     Capital Accounts.
      (a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including, without limitation, income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.
      (b) For purposes of computing the amount of any item of income, gain, loss or deduction, Simulated Depletion, Simulated Gain or Simulated Loss which is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:
        (i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement or governing, organizational or similar documents) of all property owned by (x) any other Group Member classified as a partnership for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner.
 
        (ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any,

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  shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.
 
        (iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made without regard to any election under Section 754 of the Code which may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.
 
        (iv) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.
 
        (v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery, amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery, amortization or Simulated Depletion, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery, amortization or Simulated Depletion derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for federal income tax purposes, depreciation, cost recovery, amortization or Simulated Depletion deductions shall be determined using any method that the General Partner may adopt.
 
        (vi) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

      (c) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.
      (d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests for the provision of services, or the conversion of the General Partner’s Combined Interest to Units pursuant to Section 11.3(b), the Capital Account of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Partners at such time pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that

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the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.
      (ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.
Section 5.6     Issuances of Additional Partnership Securities.
      (a) The Partnership may issue additional Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.
      (b) Each additional Partnership Security authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Securities), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may redeem the Partnership Security; (v) whether such Partnership Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Security; and (viii) the right, if any, of each such Partnership Security to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Security.
      (c) The General Partner is hereby authorized and directed to take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Securities and options, rights, warrants and appreciation rights relating to Partnership Securities pursuant to this Section 5.6, (ii) the conversion of the General Partner Interest into Units pursuant to the terms of this Agreement, (iii) the admission of additional Limited Partners and (iv) all additional issuances of Partnership Securities. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Securities or in connection with the conversion of the General Partner Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Securities are listed or admitted to trading.
      (d) No fractional Units shall be issued by the Partnership.
Section 5.7     [Reserved].

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Section 5.8     Limited Preemptive Right.
      Except as provided in this Section 5.8 and in Section 5.2(b), no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right to purchase Partnership Securities from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Securities to any Person to the extent necessary to maintain the Percentage Interests of the General Partner, with respect to the General Partner Interest, equal to that which existed immediately prior to the issuance of such Partnership Securities.
Section 5.9     Splits and Combinations.
      (a) Subject to Section 5.9(d), the Partnership may make a Pro Rata distribution of Partnership Securities to all Record Holders or may effect a subdivision or combination of Partnership Securities so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted.
      (b) Whenever such a distribution, subdivision or combination of Partnership Securities is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.
      (c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates to the Record Holders of Partnership Securities as of the applicable Record Date representing the new number of Partnership Securities held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Securities Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.
      (d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of this Section 5.9(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).
Section 5.10     Fully Paid and Non-Assessable Nature of Limited Partner Interests.
      All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 of the Delaware Act.
ARTICLE VI
Allocations and Distributions
Section 6.1     Allocations for Capital Account Purposes.
      For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction, Simulated Gain, Simulated Loss and Simulated Depletion (computed in accordance with Section 5.5(b)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided herein below.

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      (a) Net Income and Net Loss.
        (i) Net Income. After giving effect to the special allocations set forth in Section 6.1(c), Net Income for each taxable year and all items of income, gain, loss and deduction taken into account in computing Net Income for each taxable year shall be allocated to the Partners as follows:
        (A) first, to the General Partner until the General Partner has been allocated cumulative Net Income for the current and all prior taxable periods equal to the cumulative Net Loss previously allocated to the General Partner pursuant to Section 6.1(a)(ii)(C);
 
        (B) second, to the Partners, in accordance with the proportions that Net Losses were previously allocated to the Partners pursuant to Section 6.1(a)(ii)(B), until the Partners have been allocated cumulative Net Income for the current and all prior taxable periods equal to the cumulative Net Loss previously allocated to the Partners pursuant to Section 6.1(a)(ii)(B); and
 
        (C) thereafter, to the Partners in accordance with their respective Percentage Interests.
        (ii) Net Losses. After giving effect to the special allocations set forth in Section 6.1(c), Net Losses for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Losses for such taxable period shall be allocated to the Partners as follows:
        (A) first, to the Partners in accordance with their respective Percentage Interests; provided that Net Losses shall not be allocated pursuant to this Section 6.1(c)(ii)(A) to the extent that such allocation would cause any Limited Partner to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account);
 
        (B) instead, any such Net Losses shall be allocated to Partners with positive Adjusted Capital Accounts in accordance with their Percentage Interests until such positive Adjusted Capital Accounts of the Limited Partners are reduced to zero; and
 
        (C) thereafter, to the General Partner.
      (b) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(c), all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(b) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.3 have been made; provided, however, that solely for purposes of this Section 6.1(b), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4(c).
        (i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):
        (A) first, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account; and
 
        (B) second, 100% to the Partners in accordance with their respective Percentage Interests.

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        (ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:
        (A) first, to the Partners in accordance with their relative Percentage Interests, until the Capital Account of each Limited Partner has been reduced to zero; and
 
        (B) thereafter, the balance, if any, 100% to the General Partner.
      (c) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:
        (i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(c), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(c) with respect to such taxable period (other than an allocation pursuant to Section 6.1(c)(v) and Section 6.1(c)(vi)). This Section 6.1(c)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.
 
        (ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(c)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(c), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(c), other than Section 6.1(c)(i) and other than an allocation pursuant to Section 6.1(c)(v) and Section 6.1(c)(vi), with respect to such taxable period. This Section 6.1(c)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.
 
        (iii) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii).
 
        (iv) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(c)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(c)(iv) were not in this Agreement.
 
        (v) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests. If the General Partner determines

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  that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.
 
        (vi) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.
 
        (vii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.
 
        (viii) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.
 
        (ix) Curative Allocation.
 
        (A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(c)(ix)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(c)(ix)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.
 
        (B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(c)(ix)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(c)(ix)(A) among the Partners in a manner that is likely to minimize such economic distortions.

Section 6.2     Allocations for Tax Purposes.
      (a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

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      (b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Partners rather than by the Company in accordance with section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Partners in accordance with their respective Percentage Interests.
      Each Partner shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Partnership.
      (c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each partner on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Partnership’s allocable share of “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Partners as follows:
        (i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Partners in the same proportion as the depletable basis of such property was allocated to the Partners pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii));
 
        (ii) second, the remainder of such amount realized, if any, to the Partners so that, to the maximum extent possible, the amount realized allocated to each Partner under this Section 6.2(c)(ii) will equal such Partner’s share of the Simulated Gain recognized by the Partnership from such sale or disposition.
 
        (iii) The Partners recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Partners to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d).
 
        (iv) Any elections or other decisions relating to such allocations shall be made by the General Partner in any manner that reasonably reflects the purpose and intention of the Agreement.
      (d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than an oil and gas property (as defined in Section 614 of the Code), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners as follows:
        (i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.
 
        (ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(d)(i)(A);

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  and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.
 
        (iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

      (e) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including, without limitation, gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (A) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (B) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(e) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.
      (f) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Partnership’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.
      (g) Any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.
      (h) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.
      (i) Each item of Partnership income, gain, loss and deduction attributable to a transferred Partnership Interest shall, for federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and (i) prior to the time that the Units are traded on a National Securities Exchange shall be allocated to the Partners on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the first Business Day of the next succeeding month and (ii) after the time that the Units are traded on a National Securities Exchange, shall be allocated to the Partners on the first Business Day of each month as of the opening of the principal National Securities Exchange on which the Units are then traded. Notwithstanding

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the foregoing, gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners on the first Business Day of each month or, after the time that the Units are traded on a National Securities Exchange, on the first Business Day of each month as of the opening of the principal National Securities Exchange on which the Units are then traded, in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.
      (j) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.
Section 6.3      Requirement and Characterization of Distributions; Distributions to Record Holders.
      (a) Within 45 days following the end of each Quarter commencing with the Quarter ending on June 30, 2006, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners in accordance with their respective Percentage Interest as of the Record Date selected by the General Partner. All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.
      (b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all receipts received during or after the Quarter in which the Liquidation Date occurs, other than from borrowings described in (a)(ii) of the definition of Available Cash, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.
      (c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.
      (d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.
ARTICLE VII
Management and Operation of Business
Section 7.1     Management.
      (a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:
        (i) 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 Partnership Securities, and the incurring of any other obligations;

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        (ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;
 
        (iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);
 
        (iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;
 
        (v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if doing that results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);
 
        (vi) the distribution of Partnership cash;
 
        (vii) the selection and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
 
        (viii) the maintenance of insurance for the benefit of the Partnership Group and the Partners;
 
        (ix) the formation of, or acquisition of an interest in, and the contribution of cash or property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of cash or property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;
 
        (x) the control of any matters affecting the rights and obligations of the Partnership, 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 expenses and the settlement of claims and litigation;
 
        (xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;
 
        (xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);
 
        (xiii) the purchase, sale or other acquisition or disposition of Partnership Securities, or the issuance of additional options, rights, warrants and appreciation rights relating to Partnership Securities;
 
        (xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and
 
        (xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.
      (b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and each other Person who may acquire an interest in Partnership Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Underwriting Agreement, the Omnibus Agreement, the Contribution Agreement, the Founders Registration Rights Agreement, any Group Member

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Agreement of any other Group Member and the other agreements described in the Offering Memorandum that are related to the transactions contemplated by the Offering Memorandum; (ii) agrees that the General Partner (on its own or through any officer of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Offering Memorandum on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Securities; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.
Section 7.2     Certificate of Limited Partnership.
      The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.
Section 7.3     Restrictions on the General Partner’s Authority.
      (a) Except as otherwise provided in this Agreement, the General Partner may not, without written approval of the specific act by holders of all of the Outstanding Limited Partner Interests or by other written instrument executed and delivered by holders of all of the Outstanding Limited Partner Interests subsequent to the date of this Agreement, take any action in contravention of this Agreement, including, (i) committing any act that would make it impossible to carry on the ordinary business of the Partnership; (ii) possessing Partnership property, or assigning any rights in specific Partnership property, for other than a Partnership purpose; (iii) admitting a Person as a Partner; (iv) amending this Agreement in any manner; or (v) transferring its interest as a general partner of the Partnership.
      (b) Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation or other combination or sale of ownership interests of the Partnership’s Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance. Without the approval of holders of a Unit Majority, the General Partner shall not, on behalf of the Partnership, (i) except as permitted under Section 4.6, Section 11.1 and Section 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership, or (ii) consent to any amendment to the Operating Partnership Agreement or the Operating Partnership GP Agreement or, except as expressly permitted by Section 7.9(f), take any action permitted to be taken by a member of the Operating Partnership GP or any partner of the Operating Partnership, in either case, that would adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to any other class of Partnership Interests) in any material respect.

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Section 7.4     Reimbursement of the General Partner.
      (a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.
      (b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group) and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.
      (c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Securities or options to purchase or rights, warrants or appreciation rights relating to Partnership Securities), or cause the Partnership to issue Partnership Securities in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates, in each case for the benefit of employees of the General Partner, any Group Member or any Affiliate, or any of them, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Securities that the General Partner or such Affiliates are obligated to provide to any employees pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Securities purchased by the General Partner or such Affiliates from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.
Section 7.5     Outside Activities.
      (a) After the Closing Date, the General Partner, for so long as it is the general partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership) and (ii) shall not engage or allow any of its subsidiaries to engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement or (B) the acquiring, owning or disposing of debt or equity securities in any Group Member.
      (b) Except as may otherwise be provided in an agreement entered into by an Indemnitee, each Indemnitee (other than the General Partner and any of its subsidiaries) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty expressed or implied by law to any Group Member or any Partner. Except as may otherwise be provided in an agreement entered into by an Indemnitee,

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but notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Indemnitees (other than the General Partner and any of its subsidiaries) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of the General Partner or of any Indemnitee for the Indemnitees (other than the General Partner and any of its subsidiaries) to engage in such business interests and activities in preference to or to the exclusion of the Partnership.
      (c) Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Indemnitee (including the General Partner and any of its subsidiaries). No Indemnitee (including the General Partner and any of its subsidiaries) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership shall have any duty to communicate or offer such opportunity to the Partnership, and such Indemnitee (including the General Partner and any of its subsidiaries) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Indemnitee (including the General Partner and any of its subsidiaries) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership.
      (d) Except as otherwise provided by this Agreement, none of the Group Members, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Indemnitee.
      (e) The General Partner and each of its Affiliates may acquire Units or other Partnership Securities in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Securities acquired by them. For purposes of this Section 7.5(d), the term “Affiliates,” when used with respect to the General Partner, shall not include any Group Member.
Section 7.6      Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.
      (a) The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.
      (b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).
Section 7.7     Indemnification.
      (a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the

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matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates (other than a Group Member) with respect to its or their obligations incurred pursuant to the Purchase Agreement, the Omnibus Agreement or the Contribution Agreement (other than obligations incurred by the General Partner on behalf of the Partnership). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.
      (b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a determination that the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be determined that the Indemnitee is not entitled to be indemnified as authorized in this Section 7.7.
      (c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests entitled to vote on such matter, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity, and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.
      (d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.
      (e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by the Indemnitee with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interest of the Partnership.
      (f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.
      (g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.
      (h) The provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.
      (i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be

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asserted, and provided such Person became an Indemnitee hereunder prior to such amendment, modification or repeal.
Section 7.8     Liability of Indemnitees.
      (a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners or any other Persons who have acquired interests in the Partnership Securities, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.
      (b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.
      (c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.
      (d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.
Section 7.9      Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.
      (a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other hand, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and, to the fullest extent permitted by law, deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Units (excluding Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is not sought and the Board of Directors of the General Partner determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors of the General Partner acted in good faith, and in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Offering Memorandum are hereby approved by all Partners and shall not constitute a breach of this Agreement.

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      (b) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, or such Affiliates causing it to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership, unless the context otherwise requires.
      (c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner, and the General Partner, or such Affiliates causing it to do so, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrase, “at the option of the General Partner,” or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity.
      (d) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be at its option.
      (e) Except as expressly set forth in this Agreement or required by law, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.
      (f) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.
      (g) Whenever a particular transaction, arrangement or resolution of a conflict of interest is required under this Agreement to be “fair and reasonable” to any Person, the fair and reasonable nature of such transaction, arrangement or resolution shall be considered in the context of all similar or related transactions.
Section 7.10     Other Matters Concerning the General Partner.
      (a) The General Partner may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

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      (b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.
      (c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership. Each such attorney shall, to the extent provided by the General Partner in the power of attorney, have full power and authority to do and perform each and every act and duty that is permitted or required to be done by the General Partner hereunder.
      (d) Any standard of care and duty imposed by this Agreement or under the Delaware Act or any applicable law, rule or regulation shall be modified, waived or limited, to the extent permitted by law, as required to permit the General Partner to act under this Agreement and to make any decision pursuant to the authority prescribed in this Agreement, so long as such action is reasonably believed by the General Partner to be in, or not inconsistent with, the best interests of the Partnership.
Section 7.11     Purchase or Sale of Partnership Securities.
      The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Securities, such Partnership Securities shall be held by the Partnership as treasury securities unless they are expressly cancelled by action of an appropriate officer of the General Partner. As long as Partnership Securities are held by any Group Member, such Partnership Securities shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Securities for its own account, subject to the provisions of Article IV and Article X.
Section 7.12     [Reserved].
Section 7.13     Reliance by Third Parties.
      Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

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ARTICLE VIII
Books, Records, Accounting and Reports
Section 8.1     Records and Accounting.
      The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders and assignees of Units or other Partnership Securities, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.
Section 8.2     Fiscal Year.
      The fiscal year of the Partnership shall be a fiscal year ending December 31.
Section 8.3     Reports.
      (a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.
      (b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.
ARTICLE IX
Tax Matters
Section 9.1     Tax Returns and Information.
      The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and a taxable year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.
Section 9.2     Tax Elections.
      (a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code if any of the Limited Partner Interests are listed on a National Securities Exchange, the General Partner shall be authorized (but not required) to adopt a convention whereby the price

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paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted Closing Price of such Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted for trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(i) without regard to the actual price paid by such transferee.
      (b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.
Section 9.3     Tax Controversies.
      Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.
Section 9.4     Withholding.
      Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including, without limitation, pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including, without limitation, by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.
ARTICLE X
Admission of Partners
Section 10.1     Admission of Founding Investors and Initial Limited Partners.
      Upon the issuance by the Partnership of Units to the Founding Investors, the Initial Purchaser and the Accredited Investors as described in Section 5.3, the General Partner shall admit such parties to the Partnership as Initial Limited Partners in respect of the Units issued to them.
Section 10.2     Admission of Limited Partners.
      (a) By acceptance of the transfer of any Limited Partner Interests in accordance with Article IV or the acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger or consolidation pursuant to Article XIV, and except as provided in Section 4.9, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer, issuance or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement, (iv) grants the powers of attorney set forth in this Agreement and (v) makes the consents and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner

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Interest. The rights and obligations of a Person who is a Non-citizen Assignee shall be determined in accordance with Section 4.9.
      (b) The name and mailing address of each Limited Partner shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.
      (c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.2(a).
Section 10.3     Admission of Successor General Partner.
      A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.
Section 10.4     Amendment of Agreement and Certificate of Limited Partnership.
      To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership, and the General Partner may for this purpose, among others, exercise the power of attorney granted pursuant to Section 2.6.
ARTICLE XI
Withdrawal or Removal of Partners
Section 11.1     Withdrawal of the General Partner.
      (a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);
        (i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;
 
        (ii) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;
 
        (iii) The General Partner is removed pursuant to Section 11.2;
 
        (iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

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        (v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or
 
        (vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.
If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.
      (b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Central Time, on March 31, 2016, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Units (excluding Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner or any Group Member or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, Central Time, on March 31, 2016, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Unitholders as provided in this Agreement or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.3.
Section 11.2     Removal of the General Partner.
      The General Partner may be removed if such removal is approved by the Unitholders holding at least 662/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the outstanding Units voting

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as a single class (including Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.3. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.3, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.3.
Section 11.3     Interest of Departing General Partner and Successor General Partner.
      (a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner, to require its successor to purchase its General Partner Interest and its general partner interest (or equivalent interest), if any, in the other Group Members (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its departure. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest of the Departing General Partner. In either event, the Departing Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.
      For purposes of this Section 11.3(a), the fair market value of the Departing General Partner’s Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing Partner’s departure, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such departure, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest of the Departing General Partner. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner and other factors it may deem relevant.
      (b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be

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converted into Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Units will be characterized as if the Departing General Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Units.
      (c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of the Percentage Interest of the Departing Partner and the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.
Section 11.4     [Reserved].
Section 11.5     Withdrawal of Limited Partners.
      No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.
ARTICLE XII
Dissolution and Liquidation
Section 12.1     Dissolution.
      The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or Section 11.2, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. Subject to Section 12.2, the Partnership shall dissolve, and its affairs shall be wound up, upon:
        (a) an election to dissolve the Partnership by the Board of Directors of the General Partner that is approved by the holders of a Unit Majority;
 
        (b) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act;
 
        (c) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) or Section 11.2 and such successor is admitted to the Partnership pursuant to Section 10.3; or
 
        (d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

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Section 12.2     Continuation of the Business of the Partnership After Dissolution.
      Upon (a) an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter or (b) an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, in either case, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business without dissolution of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall dissolve and conduct only activities necessary to wind up its affairs. If such an election is so made, then:
        (i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;
 
        (ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and
 
        (iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement; provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor any Group Member 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 such right to continue (to the extent not already so treated or taxed).
Section 12.3     Liquidator.
      Upon dissolution of the Partnership, unless the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by the holders of at least a majority of the Outstanding Units voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by the holders of at least a majority of the Outstanding Units voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by the holders of at least a majority of the Outstanding Units voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.
Section 12.4     Liquidation.
      The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:
        (a) Disposition of Assets. The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partners receiving the property shall be deemed for

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  purposes of Section 12.4(c) to have received cash equal to the fair market value of the property distributed; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.
 
        (b) Discharge of Liabilities. Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.
 
        (c) Liquidation Distributions. All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable year of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 12.5     Cancellation of Certificate of Limited Partnership.
      Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.
Section 12.6     Return of Contributions.
      The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.
Section 12.7     Waiver of Partition.
      To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.
Section 12.8     Capital Account Restoration.
      No Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership.

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ARTICLE XIII
Amendment of Partnership
Agreement; Meetings; Record Date
Section 13.1     Amendments to be Adopted Solely by the General Partner.
      Each Partner agrees that the General Partner, without the approval of any Partner may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:
        (a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;
 
        (b) the admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;
 
        (c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;
 
        (d) a change that the General Partner determines, (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) 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 (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or advisable in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;
 
        (e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;
 
        (f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;
 
        (g) an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.6;
 
        (h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;
 
        (i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;
 
        (j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation,

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  partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;
 
        (k) a merger or conveyance pursuant to Section 14.3(d); or
 
        (l) any other amendments substantially similar to the foregoing.

Section 13.2     Amendment Procedures.
      Except as provided in Section 13.1 and Section 13.3, all amendments to this Agreement shall be made in accordance with the following requirements. Amendments to this Agreement may be proposed only by the General Partner; provided, however, that the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to propose an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments.
Section 13.3     Amendment Requirements.
      (a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.
      (b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) 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 to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.
      (c) Except as provided in Section 14.3, and without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.
      (d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable law.
      (e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

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Section 13.4     Meetings.
      (a) All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII.
      (b) Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Limited Partner Interests of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A special meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting. Limited Partners shall not vote at any special meeting for the election of directors to the Board of Directors of the General Partner or on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.
      (c) (i) An annual meeting of Limited Partners for the election of directors to the Board of Directors of the General Partner and such other matters as the Board of Directors of the General Partner shall submit to a vote of the Limited Partners shall be held, following the first to occur of (A) the Founding Investors ceasing to own in the aggregate 50% or more of the Outstanding Units or (B) the closing of an Initial Public Offering, in either case on the second Wednesday in May of each year if a Business Day, and if not a Business Day, then on the next Business Day following, at 10 a.m., or at such other date and time as may be fixed from time to time by the General Partner at such place within or without the State of Delaware as may be fixed from time to time by the General Partner and all as stated in the notice of the meeting. Notice of the annual meeting shall be given in accordance with Section 13.5 not less than 10 days nor more than 60 days prior to the date of such meeting.
      (ii) The Limited Partners entitled to vote at the annual meeting shall vote together as a single class. The Limited Partners entitled to vote shall elect by a plurality of the votes cast at such meeting persons to serve on the Board of Directors of the General Partner who are nominated in accordance with the provisions of this Section 13.4(c). The exercise by a Limited Partner of the right to elect the Directors and any other rights afforded to such Limited Partner under this Section 13.4(c) shall be in such Limited Partner’s capacity as a limited partner of the Partnership and shall not cause a Limited Partner to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize such Limited Partner’s limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.
      (iii) Each Limited Partner entitled to vote shall be entitled to one vote for each Outstanding Unit that is registered in the name of such Limited Partner on the Record Date for such meeting; provided, however that, prior to the closing of an Initial Public Offering, the Limited Partners will be entitled to elect only: (A) three persons to serve on the Board of Directors of the General Partner who are nominated in accordance with the provisions of this Section 13.4(c) following the time and for so long as the Founding Investors own less than 50% but greater than or equal to 35% of the Outstanding Units, (B) five persons to serve on the Board of Directors of the General Partner who are nominated in accordance with the provisions of this Section 13.4(c) following the time and for so long as the Founding Investors own is less than 35% but greater than or equal to 20% of the Outstanding Units; and (C) all persons to serve on the Board of Directors of the General Partner who are nominated in accordance with the provisions of this Section 13.4(c) following the time and for so long as the Founding Investors own less than 20% of the Outstanding Units. All directors not elected

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by the Limited Partners in accordance with this Section 13.4(c)(iii) shall be appointed by the GP Members in accordance with the limited liability company agreement of the General Partner.
      (iv) Immediately following the Closing and prior to an Initial Public Offering, the number of Directors that shall constitute the whole Board of Directors of the General Partner shall initially be four but shall be increased to equal seven with the vacancies to be filled by the existing Directors as follows: (A) one Independent Director will be added promptly following the Closing Date; (B) one Independent Director will be added on or before sixty (60) days following the Closing Date; and (C) one Independent Director will be added on or before the first anniversary of the Closing Date. Following an Initial Public Offering, the number of Directors shall not be less than seven nor more than nine as shall be established from time to time by a resolution adopted by a majority of the Directors then in office, provided that no decrease shall shorten the term of the any incumbent Director.
      (v) Each Director shall hold office for the term for which such Director is elected and thereafter until such Director’s successor shall have been duly elected and qualified, or until such Director’s earlier death, resignation or removal. Any vacancies may be filled, until the next annual meeting at which the term of such class expires, by a majority of the remaining Directors then in office. A Director may be removed only for cause and only upon a vote of the majority of the remaining Directors then in office.
      (vi) Nominations of persons for election to the Board of Directors of the General Partner may be made at an annual meeting only (A) by or at the direction of the General Partner or the Board of Directors of the General Partner or (B) by any Limited Partner who was a Record Holder of Outstanding Units at the time of giving notice provided for in this Agreement, who is entitled to vote at the meeting and who complies with the notice procedures set forth below; provided, however, that following the Initial Public Offering such nominations shall be subject to the requirement that the Board of Directors of the General Partner have and maintain at least three Directors meeting the independence and experience requirements as set forth most recently by any National Securities Exchange on which any Units or other Partnership Securities are or may be listed or quoted; and provided, further that nominations by any Limited Partner may only be made for that number of Directors for which the Limited Partners are entitled to vote as provided in this Section 13.4(c). For nominations by a Limited Partner pursuant to clause (B) above, the Limited Partner must have given timely notice thereof in writing to the General Partner. To be timely, a Limited Partner’s notice shall be delivered to the General Partner at the principal executive offices of the General Partner not later than the close of business on the 120th calendar day, nor earlier than the close of business on the 135th calendar day, prior to the first anniversary of the preceding year’s annual meeting. The adjournment of an annual meeting shall not commence a new time period for the giving of a Limited Partner’s notice as described above. Such Limited Partner’s notice shall set forth (Y) as to each person whom the Limited Partner proposes to nominate for election or reelection as a Director all information relating to such person that is required to be disclosed in solicitations of proxies for the election of directors in an election contest, or is otherwise required, in each case, pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (including such person’s written consent to being named in the proxy statement as a nominee and to serving as a Director if elected); and (Z) as to the Limited Partner giving the notice (1) the name and address of such Limited Partner, and (2) the class and number of Units which are owned by such Limited Partner. Other than as provided in Section 13.4(c)(v), only such persons who are nominated in accordance with the procedures set forth in this provision shall be eligible to serve as Directors. The chairman of the meeting shall have the power and duty to determine whether a nomination was made in accordance with the procedures set forth above and to declare that such defective nomination shall be disregarded.
      (vii) This Section 13.4(c) shall not be deemed in any way to limit or impair the ability of the General Partner, or the Board of Directors of the General Partner on behalf of the General Partner, to adopt a “poison pill” or unitholder or other similar rights plan with respect to the Partnership, whether such poison pill or plan contains “dead hand” provisions, “no hand” provisions or other provisions relating to the redemption of the poison pill or plan, in each case as such terms are used under Delaware common law.
      (viii) Notwithstanding any other provision of this Agreement, a majority of the Board of Directors of the General Partner may be nominated and elected to the extent provided in the Registration Rights Agreement.

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      (ix) The General Partner shall use its commercially reasonable best efforts to take such action as shall be necessary or appropriate to give effect to and implement the provisions of this Section 13.4(c), including, without limitation, amending the limited liability company agreement of the General Partner.
      (x) This Section 13.4(c) may not be amended except upon the prior approval of Limited Partners that hold three-fourths of the Outstanding Units.
      (xi) If the General Partner delegates to an existing or newly formed wholly-owned subsidiary the power and authority to manage and control the business and affairs of the Partnership Group, the foregoing provisions of this Section 13.4(c) shall be applicable with respect to the board of directors or other governing body of such subsidiary.
Section 13.5     Notice of a Meeting.
      Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.
Section 13.6     Record Date.
      For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.
Section 13.7     Adjournment.
      When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business that might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.
Section 13.8     Waiver of Notice; Approval of Meeting; Approval of Minutes.
      The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.
Section 13.9     Quorum and Voting.
      The holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) represented in person or by proxy

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shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement (including Outstanding Units deemed owned by the General Partner). In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units entitled to vote at such meeting (including Outstanding Units deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.
Section 13.10     Conduct of a Meeting.
      The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.
Section 13.11     Action Without a Meeting.
      If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting, without prior notice and without a vote if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Units deemed owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the

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business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.
Section 13.12     Right to Vote and Related Matters.
      (a) Only those Record Holders of the Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.
      (b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.
ARTICLE XIV
Merger
Section 14.1     Authority.
      The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited and including a limited liability partnership), formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation (“Merger Agreement”) in accordance with this Article XIV.
Section 14.2     Procedure for Merger or Consolidation.
      Merger or consolidation of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner; provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger or consolidation of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger or consolidation, to the fullest extent permitted by law, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:
        (a) the names and jurisdictions of formation or organization of each of the business entities proposing to merge or consolidate;
 
        (b) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);
 
        (c) the terms and conditions of the proposed merger or consolidation;
 
        (d) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or interests,

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  rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;
 
        (e) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;
 
        (f) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and
 
        (g) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

Section 14.3     Approval by Limited Partners of Merger or Consolidation.
      (a) Except as provided in Section 14.3(d) or Section 14.3(e), the General Partner, upon its approval of the Merger Agreement, shall direct that the Merger Agreement be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement shall be included in or enclosed with the notice of a special meeting or the written consent.
      (b) Except as provided in Section 14.3(d) or Section 14.3(e), the Merger Agreement shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority.
      (c) Except as provided in Section 14.3(d) or Section 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger pursuant to Section 14.4, the merger or consolidation may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement.
      (d) Notwithstanding anything else contained in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity which shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with rights and obligations that are, in all material respects, the same rights and obligations as are herein contained.
      (e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or

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consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to the Partnership Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Securities to be issued by the Partnership in such merger or consolidation do not exceed 20% of the Partnership Securities Outstanding immediately prior to the effective date of such merger or consolidation.
Section 14.4     Certificate of Merger.
      Upon the required approval by the General Partner and the Unitholders of a Merger Agreement, a certificate of merger shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.
Section 14.5     Amendment of Partnership Agreement.
      Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.5 shall be effective at the effective time or date of the merger or consolidation.
Section 14.6     Effect of Merger.
      (a) At the effective time of the certificate of merger:
        (i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;
 
        (ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;
 
        (iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and
 
        (iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.
      (b) A merger or consolidation effected pursuant to this Article XIV shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.
ARTICLE XV
Right to Acquire Limited Partner Interests
Section 15.1     Right to Acquire Limited Partner Interests.
      (a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 85% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General

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Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed. As used in this Agreement, (i) “Current Market Price” as of any date of any class of Limited Partner Interests listed or admitted to trading on any National Securities Exchange means the average of the daily Closing Prices (as hereinafter defined) per Limited Partner Interest of such class for the 20 consecutive Trading Days (as hereinafter defined) immediately prior to such date; (ii) “Closing Price” for any day means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange (other than The Nasdaq Stock Market) on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests of such class are not listed or admitted to trading on any National Securities Exchange (other than The Nasdaq Stock Market), the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by The Nasdaq Stock Market or such other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner; and (iii) “Trading Day” means a day on which the principal National Securities Exchange on which such Limited Partner Interests of any class are listed or admitted to trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.
      (b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article IV, Article  V, Article VI and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited

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Partner Interests, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article IV, Article V, Article VI and Article XII).
      (c) At any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.
ARTICLE XVI
General Provisions
Section 16.1     Addresses and Notices.
      Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Partnership is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.
Section 16.2     Further Action.
      The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.
Section 16.3     Binding Effect.
      This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.
Section 16.4     Integration.
      This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

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Section 16.5     Creditors.
      None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.
Section 16.6     Waiver.
      No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.
Section 16.7     Third-Party Beneficiaries
      Each Partner agrees that any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee.
Section 16.8     Counterparts.
      This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest pursuant to Section 10.2(a) without execution of this Agreement.
Section 16.9     Applicable Law.
      This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.
Section 16.10     Invalidity of Provisions.
      If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.
Section 16.11     Consent of Partners.
      Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.
Section 16.12     Facsimile Signatures.
      The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on certificates representing Units is expressly permitted by this Agreement.
[REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK.]

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      IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.
  GENERAL PARTNER:
 
  LEGACY RESERVES GP, LLC
 
  By: /s/ Steven H. Pruett
 
 
  Name: Steven H. Pruett
 
 
  Title: President, Chief Financial Officer and Secretary
 
 
 
  LIMITED PARTNERS
 
  All Limited Partners now and hereafter admitted as Limited Partners of the Partnership, pursuant to powers of attorney now and hereafter executed in favor of, and granted and delivered to the General Partner or without execution hereof pursuant to Section 10.2(a) hereof.
 
  LEGACY RESERVES GP, LLC
 
  By: /s/ Steven H. Pruett
 
 
  Name: Steven H. Pruett
 
 
  Title: President, Chief Financial Officer and Secretary
 
 
 
  ORGANIZATIONAL LIMITED PARTNER:
 
  MORIAH PROPERTIES, LTD.
  By: Moriah Resources, Inc., its general partner
 
  By: /s/ Dale A. Brown
 
 
  Name: Dale A. Brown
 
 
  Title: President
 
 

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EXHIBIT A
to the Amended and Restated
Agreement of Limited Partnership of
Legacy Reserves LP
Certificate Evidencing Units
Representing Limited Partner Interests in
Legacy Reserves LP
     

No.                                                   
  
                                                   Units
   
CUSIP                                                   
      In accordance with Section 4.1 of the Amended and Restated Agreement of Limited Partnership of Legacy Reserves LP, as amended, supplemented or restated from time to time (the “Partnership Agreement”), Legacy Reserves LP, a Delaware limited partnership (the “Partnership”), hereby certifies that                     (the “Holder”) is the registered owner of                      Units representing limited partner interests in the Partnership (the “Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Units are set forth in, and this Certificate and the Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 303 W. Wall Street, Ste. 1600, Midland, Texas 79701. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.
      THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF LEGACY RESERVES LP THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF LEGACY RESERVES LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE LEGACY RESERVES LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). LEGACY RESERVES GP, LLC, THE GENERAL PARTNER OF LEGACY RESERVES LP, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF LEGACY RESERVES LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.
      The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

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      This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.
      This Certificate shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to principles of conflict of laws thereof.
     
Dated: 
   Legacy Reserves LP
     
 
Countersigned and Registered by:
   By:  Legacy Reserves GP, LLC,
its General Partner
 
    By: 
     
as Transfer Agent and Registrar
  
Name: 
     
 
By: 
 
Authorized Signature
   By: 
 
Secretary
[Reverse of Certificate]
ABBREVIATIONS
      The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:
TEN COM – as tenants in common
TEN ENT – as tenants by the entireties
JT TEN – as joint tenants with right of
survivorship and not as
tenants in common
UNIF GIFT/TRANSFERS MIN ACT
                           Custodian                           
(Cust)                                               (Minor)
under Uniform Gifts/Transfers to CD
Minors Act (State)
      Additional abbreviations, though not in the above list, may also be used.
ASSIGNMENT OF UNITS
in
LEGACY RESERVES LP
      FOR VALUE RECEIVED,                     hereby assigns, conveys, sells and transfers unto
 
(Please print or typewrite name and address of assignee)
 
(Please insert Social Security or other identifying number of assignee)
                    Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint                     as its attorney-in-fact with full power of substitution to transfer the same on the books of Legacy Reserves LP
Date: 
 
NOTE:  The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.

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THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17d-15
 
  
 
(Signature)



 
(Signature)
Signature(s) Guaranteed
      No transfer of the Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Units to be transferred is surrendered for registration or transfer.

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APPENDIX B
GLOSSARY OF TERMS
      Available Cash means, for any quarter ending prior to liquidation:
      (a) the sum of:
        (i) all cash and cash equivalents of Legacy Reserves LP and its subsidiaries on hand at the end of that quarter; and
 
        (ii) all additional cash and cash equivalents of Legacy Reserves LP and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made subsequent to the end of the quarter,
      (b) less the amount of any cash reserves established by our general partner to
        (i) provide for the proper conduct of the business of Legacy Reserves LP and its subsidiaries (including reserves for future capital expenditures including drilling and acquisitions and for anticipated future credit needs),
 
        (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which Legacy Reserves LP or any of its subsidiaries is a party or by which it is bound or its assets are subject; or
 
        (iii) provide funds for distributions with respect to any one or more of the next four quarters;
provided, that disbursements made by Legacy Reserves LP or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if Legacy Reserves GP LLC so determines.
      Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.
      Bcf. Billion cubic feet.
      Boe. One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
      Boe/d. Barrels of oil equivalent per day.
      Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
      Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
      Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
      Dry hole or 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.
      Exploitation. A drilling 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.
      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.
      Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

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      MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
      MBoe. One thousand barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
      Mcf. One thousand cubic feet.
      MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
      MMBoe. One million barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
      MMBtu. One million British thermal units.
      MMcf. One million cubic feet.
      Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
      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. Crude oil, condensate and natural gas liquids.
      Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
      Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
      Proved developed non-producing or PDNP’s. Proved oil and natural gas reserves that are developed behind pipe, shut-in or can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. 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 started producing, (2) wells that 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 that will require additional completion work or future recompletion prior to the start of production.
      Proved reserves. Proved oil and natural gas reserves are the estimated quantities of natural gas, crude oil and natural gas liquids that geological and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
      Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
      Proved undeveloped reserves or PUDs. 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 shall be 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

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technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
      Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
      Reserve Acquisition Costs. The total consideration paid for an oil and natural gas property or set of properties, which includes the cash purchase price and any value ascribed to units issued to a seller adjusted for any post-closing items.
      Reserve Replacement. The replacement of oil and natural gas produced with reserve additions from acquisitions, reserve additions and reserve revisions.
      Reserve Replacement Cost. An amount per BOE equal to the sum of costs incurred relating to oil and natural gas property acquisition, exploitation, development and exploration activities (as reflected in our year-end financial statements for the relevant year) divided by the sum of all additions and revisions to estimated proved reserves, including reserve purchases. The calculation of reserve additions for each year is based upon the reserve report of our independent engineers. Management uses reserve replacement cost to compare our company to others in terms of our historical ability to increase our reserve base in an economic manner. However, past performance does not necessarily reflect future reserve replacement cost performance. For example, increases in oil and natural prices in recent years have increased the economic life of reserves adding additional reserves with no required capital expenditures. On the other hand, increases in oil and natural gas prices have increased the cost of reserve purchases and reserves added through exploitation. The reserve replacement cost may not be indicative of the economic value added of the reserves due to differing lease operating expenses per barrel and differing timing of production.
      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.
      Standardized measure. 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 (using prices and costs in effect as of the period end date) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. Standardized measure does not give effect to derivative transactions.
      Successful well. A well that we have completed or as to which we have a defined plan to complete.
      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.
      Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
      Workover. Operations on a producing well to restore or increase production.

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APPENDIX C
October 24, 2006
Mr. Kyle McGraw
Legacy Reserves LP
303 W. Wall St., Suite 1600
Midland, TX 79701
Dear Mr. McGraw:
      At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has estimated the proved developed reserves and future cash flow, as of June 30, 2006, to the Legacy Reserves LP (Legacy) interest in certain properties located in New Mexico and Texas which were acquired from Kinder Morgan, Inc. (KM) in July 2006. This report has been prepared using constant prices and costs and conforms to our understanding of the guidelines of the Securities and Exchange Commission (SEC).
      Summarized below are LPC’s estimates of net reserves and future net cash flow. Future net revenue is prior to deducting estimated production and ad valorem taxes. Future net cash flow is after deducting these taxes and operating expenses but before consideration of federal income taxes. The discounted cash flow values included in this report are intended to represent the time value of money and should not be construed to represent an estimate of fair market value. We estimate the proved net reserves and future net cash flow to the Legacy interest, as of June 30, 2006, to be:
                                   
    Net Reserves   Future Net Cash Flow ($)
         
    Oil   Gas       Present Worth
Category and Entity   (Barrels)   (Mcf)   Total   at 10%
                 
Proved Developed Producing
     1,118,404       558,219     $ 43,071,684     $ 22,604,445  
 
Non-producing
     0       0       0       0  
Proved Undeveloped
     166,331       71,229       5,110,829       1,985,853  
                         
Total Proved(1)
     1,354,735       629,448       48,182,513       24,590,298  
 
(1)  The total proved values above may or may not match those values on the summary page that follows this letter due to rounding by the economics program.
      The oil reserves include crude oil and condensate. Oil reserves are expressed in barrels, which are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases.
      The estimated reserves and future cash flow shown in this report are for proved developed producing reserves and, for certain properties, proved developed non-producing and proved undeveloped reserves. This report does not include any value that could be attributed to interest in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Definitions of all reserve categories used in this report are presented immediately following this letter.
      This report includes: (1) summary economic projections of reserves and cash flow for each reserve category, (2) one-line summaries of basic economic data and reserves for each property evaluated, and (3) economic projections of reserves and cash flow for each evaluated property.
      Our estimates of reserves were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and

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reservoir and well performance. In some instances, comparisons were made with similar properties where more complete data were available.
      The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices. The prices on June 30, 2006 were used in the preparation of these estimates as required by SEC guidelines; however, actual future prices may vary significantly from the June 30, 2006 prices. Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this report.
      Oil prices are referenced to a June 30, 2006 West Texas Intermediate (WTI) physical price of $70.50 per barrel, as posted by Plains All American LP, adjusted for gravity, crude quality, transportation fees, and regional price differentials. Gas prices are referenced to a June 30, 2006 Henry Hub physical price of $6.09 per MMBtu, as published in the Platts Gas Daily, adjusted for energy content, transportation fees, and regional price differentials. Prices are held constant in accordance with SEC guidelines. For reference purposes, the corresponding NYMEX futures contract closing prices for the nearest month contracts being traded on June 30, 2006 were $73.92 per barrel for West Texas Intermediate crude oil and $6.06 per MMBtu for Henry Hub gas.
      Lease and well operating expenses are based on data obtained from Legacy. As requested, lease and well operating costs for the properties operated by Legacy include only direct lease and field level costs. For properties operated by others, these costs include the per-well overhead expenses allowed under joint operating agreements along with costs estimated to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Legacy are not included. Lease and well operating costs are held constant in accordance with SEC guidelines.
      Capital costs and timing of all investments have been provided by Legacy and are included as required for workovers, new development wells, and production equipment. These costs are also held constant.
      LPC made no investigation of possible oil and gas volume and value imbalances that may have been the result of overdelivery or underdelivery to the Legacy interest. Our projections are based on the Legacy interest receiving its net revenue interest share of estimated future gross oil and gas production.
      Technical information necessary for the preparation of the reserve estimates herein was furnished by Legacy or was obtained from state regulatory agencies and commercially available data sources. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, the individual well test and production data as reported by the above sources were accepted as represented together with all other factual data presented by the Legacy including the extent and character of the interest evaluated.
      An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC. Consideration was given to salvage values and abandonment costs for all of the properties. In addition, the costs associated with the continued operation of uneconomic properties is not reflected in the cash flows.
      The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein.
      The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. These reserve estimates are subject to a

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greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data. Therefore, our conclusions represent informed professional judgments only, not statements of fact.
      This report is solely for the use of Legacy, its agents, and its representatives in their evaluation of these properties and is not to be used, circulated, quoted, or otherwise referenced for any other purpose without the express written consent of the undersigned except as required by law. Persons other than those to whom this report is addressed or those authorized by the addressee shall not be entitled to rely upon the report unless it is accompanied by such consent.
      We are independent petroleum engineers, geologists, and geophysicists; we do not own an interest in these properties and are not employed on a contingent basis. Data pertinent to this report are maintained on file in our office.
  Very truly yours,
  LaRoche Petroleum Consultants, Ltd.
 
  /s/ Joe A. Young
 
  Joe A. Young
  Senior Partner
  Licensed Professional Engineer
  State of Texas No. 62866
 
  /s/ Al Iakovakis
 
  Al Iakovakis
  Senior Staff Engineer

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ECONOMIC SUMMARY PROJECTION
LEGACY RESERVES GP, LLC
Total Proved (KM)
Discount Rate: 10.00  
       As of: 7/1/2006
             
Est. Cum Oil Mbbl :
   26,418.788   KINDER MORGAN ACQUISITION    
Est. Cum Gas (MMcf) :
   9,989.180   June 30, 2006 SEC Pricing    
Est. Cum Water (Mbbl) :
   88,617.571   Plains WTI $70.50/bbl, Platts HH $6.09/MMBtu    
 
                                                                                                                     
        Oil   Gas   Oil   Gas   Oil   Gas   Oil & Gas   Misc.   Costs   Taxes   Invest.   NonDisc. CF   Cum    
        Gross   Gross   Net   Net   Price   Price   Rev. Net   Rev. Net   Net   Net   Net   Annual   Disc.CF    
    Year   (Mbbl)   (MMcf)   (Mbbl)   (MMcf)   ($/bbl)   ($/Mcf)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)    
 
      2006       180.758       67.973       47.690       18.369       71.38       2.81       3,455.534       0.000       905.319       287.495       0.000       2,262.720       2,207.391      
      2007       336.860       136.220       96.741       41.014       71.47       2.99       7,036.834       0.000       1,963.249       585.072       829.500       3,659.012       5,511.687      
      2008       287.874       118.216       87.499       37.842       71.48       2.96       6,366.826       0.000       1,938.178       529.844       0.000       3,898.803       8,736.481      
      2009       267.204       110.580       81.235       35.788       71.49       2.95       5,912.994       0.000       1,938.178       492.277       0.000       3,482.539       11,354.378      
      2010       251.700       105.198       75.342       34.145       71.48       2.95       5,486.374       0.000       1,885.816       456.772       0.000       3,143.786       13,502.875      
      2011       237.534       100.129       70.218       32.617       71.48       2.94       5,115.161       0.000       1,843.198       425.899       0.000       2,846.064       15,271.153      
      2012       223.947       93.582       64.874       29.504       71.47       2.97       4,724.021       0.000       1,740.014       393.128       0.000       2,590.879       16,734.518      
      2013       211.422       88.622       60.824       27.925       71.47       2.97       4,429.845       0.000       1,726.918       368.719       0.000       2,334.207       17,932.911      
      2014       199.435       84.407       56.616       26.716       71.48       2.96       4,126.187       0.000       1,671.509       343.672       0.000       2,111.006       18,918.233      
      2015       188.693       80.408       53.137       25.568       71.49       2.96       3,874.377       0.000       1,641.718       322.846       0.000       1,909.813       19,728.657      
      2016       176.298       75.874       48.255       24.274       71.53       2.91       3,522.109       0.000       1,488.829       293.872       14.510       1,724.898       20,393.955      
      2017       164.792       71.064       43.924       22.484       71.58       2.90       3,209.323       0.000       1,367.954       267.535       0.000       1,573.834       20,945.802      
      2018       156.285       67.656       41.430       21.436       71.59       2.90       3,028.204       0.000       1,346.050       252.411       0.000       1,429.742       21,401.580      
      2019       148.596       64.546       39.406       20.554       71.59       2.90       2,880.680       0.000       1,346.050       240.146       0.000       1,294.483       21,776.753      
      2020       140.734       61.746       36.767       19.762       71.59       2.90       2,689.397       0.000       1,290.300       224.366       0.000       1,174.731       22,086.284      
 
Rem.
             1,883.439       779.364       386.203       211.450       71.42       2.77       28,169.019       0.000       16,306.233       2,347.248       0.000       9,515.538       1,356.232      
Total
     50.0       5,055.569       2,105.584       1,290.160       629.448       71.47       2.88       94,026.885       0.000       40,399.516       7,831.304       844.010       44,952.055       23,442.516      
                                                                                         
Ult.     31,474.358       12,094.765                                                                                              
                         
Eco. Indicators                
                 
Return on Investment (disc) :
   30.856                    
Return on Investment  (undisc) :
   54.260   Present Worth Profile (M$)        
Years to Payout :
   0.205                    
Internal Rate of Return(%) :
   >1000.0   PW 5.00% :   30,777.983   PW 20.00% :     16,087.553  
        PW 8.00% :   25,895.103   PW 30.00% :     12,429.428  
        PW 10.00% :   23,442.516   PW 40.00% :     10,242.896  
        PW 12.00% :   21,434.272   PW 50.00% :     8,787.685  
        PW 15.00% :   19,025.591   PW 60.00% :     7,748.491  
 
THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. Page 1 of 1 

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ECONOMIC SUMMARY PROJECTION
LEGACY RESERVES GP, LLC
Proved Developed Producing (KM)
Discount Rate: 10.00  
       As of:  7/1/2006
         
Est. Cum Oil Mbbl :
   22,354.083   KINDER MORGAN ACQUISITION
Est. Cum Gas (MMcf) :
   8,614.931   June 30, 2006 SEC Pricing
Est. Cum Water (Mbbl) :
   79,003.062   Plains WTI $70.50/bbl, Platts HH $6.09/MMBtu
 
                                                                                                                     
        Oil   Gas   Oil   Gas   Oil   Gas   Oil & Gas   Misc.   Costs   Taxes   Invest.   NonDisc. CF   Cum    
        Gross   Gross   Net   Net   Price   Price   Rev. Net   Rev. Net   Net   Net   Net   Annual   Disc. CF    
    Year   (Mbbl)   (MMcf)   (Mbbl)   (MMcf)   ($/bbl)   ($/Mcf)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)    
 
      2006       180.758       67.973       47.690       18.369       71.38       2.81       3,455.534       0.000       905.319       287.495       0.000       2,262.720       2,207.391      
      2007       318.991       123.712       89.621       36.030       71.41       2.87       6,503.596       0.000       1,762.249       541.303       0.000       4,200.045       6,030.844      
      2008       267.378       103.869       79.333       32.126       71.41       2.80       5,755.221       0.000       1,696.978       479.642       0.000       3,578.601       8,990.868      
      2009       247.787       96.988       73.498       30.372       71.41       2.80       5,333.577       0.000       1,696.978       444.717       0.000       3,191.882       11,390.302      
      2010       233.254       92.286       67.992       29.000       71.41       2.79       4,935.909       0.000       1,644.616       411.588       0.000       2,879.704       13,358.339      
      2011       220.009       87.862       63.235       27.729       71.40       2.78       4,592.201       0.000       1,601.998       382.973       0.000       2,607.230       14,978.236      
      2012       207.253       81.896       58.223       24.848       71.38       2.81       4,225.865       0.000       1,498.814       352.238       0.000       2,374.813       16,319.560      
      2013       195.607       77.552       54.523       23.514       71.38       2.80       3,957.906       0.000       1,485.718       329.981       0.000       2,142.207       17,419.377      
      2014       184.410       73.890       50.629       22.525       71.40       2.80       3,677.830       0.000       1,430.309       306.869       0.000       1,940.651       18,325.182      
      2015       174.419       70.416       47.449       21.587       71.41       2.79       3,448.423       0.000       1,400.518       287.882       0.000       1,760.022       19,072.035      
      2016       162.701       66.357       42.838       20.482       71.44       2.74       3,116.358       0.000       1,247.629       260.567       14.510       1,593.652       19,686.690      
      2017       151.911       62.047       38.792       18.891       71.50       2.72       2,824.926       0.000       1,126.754       235.983       0.000       1,462.189       20,199.380      
      2018       144.047       59.089       36.554       18.023       71.51       2.72       2,663.014       0.000       1,104.850       222.435       0.000       1,335.728       20,625.177      
      2019       136.970       56.407       34.773       17.311       71.51       2.72       2,533.737       0.000       1,104.850       211.668       0.000       1,217.219       20,977.948      
      2020       129.659       53.993       32.354       16.673       71.51       2.72       2,358.910       0.000       1,049.100       197.238       0.000       1,112.572       21,271.087      
 
Rem.
             1,845.029       752.477       370.899       200.737       71.39       2.72       27,022.813       0.000       15,357.200       2,253.164       0.000       9,412.449       1,333.358      
Total
     50.0       4,800.183       1,926.814       1,188.404       558.219       71.41       2.76       86,405.820       0.000       36,113.883       7,205.743       14.510       43,071.684       22,604.445      
                                                                                         
Ult.     27,154.266       10,541.745                                                                                              
                         
Eco. Indicators                
                 
Return on Investment (disc) :
   3,971.121                    
Return on Investment (undisc) :
   2,969.414   Present Worth Profile (M$)        
Years to Payout :
   0.005                    
Internal Rate of Return (%) :
   >1000.0   PW 5.00% :   29,533.782   PW 20.00% :     15,712.255  
        PW 8.00% :   24,914.671   PW 30.00% :     12,294.198  
        PW 10.00% :   22,604.445   PW 40.00% :     10,246.145  
        PW 12.00% :   20,717.630   PW 50.00% :     8,876.823  
        PW 15.00% :   18,459.917   PW 60.00% :     7,893.628  
 
THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. Page 1 of 1 

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ECONOMIC SUMMARY PROJECTION
LEGACY RESERVES GP, LLC
Proved Developed Non-Producing (KM)
Discount Rate: 10.00  
       As of: 7/1/2006
             
Est. Cum Oil Mbbl :
   1,376.426   KINDER MORGAN ACQUISITION    
Est. Cum Gas (MMcf) :
   656.077   June 30, 2006 SEC Pricing    
Est. Cum Water (Mbbl) :
   5,728.647   Plains WTI $70.50/bbl, Platts HH $6.09/ MMBtu    
 
                                                                                                                     
        Oil   Gas   Oil   Gas   Oil   Gas   Oil & Gas   Misc.   Costs   Taxes   Invest.   NonDisc. CF   Cum    
        Gross   Gross   Net   Net   Price   Price   Rev. Net   Rev. Net   Net   Net   Net   Annual   Disc. CF    
    Year   (Mbbl)   (MMcf)   (Mbbl)   (MMcf)   ($/bbl)   ($/Mcf)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)    
 
      2006       0.000       0.000       0.000       0.000       0.00       0.00       0.000       0.000       0.000       0.000       0.000       0.000       0.000      
 
 
Rem.
             0.000       0.000       0.000       0.000       0.00       0.00       0.000       0.000       0.000       0.000       0.000       0.000       0.000      
Total
     0.0       0.000       0.000       0.000       0.000       0.00       0.00       0.000       0.000       0.000       0.000       0.000       0.000       0.000      
                                                                                         
Ult.     1,376.426       656.077                                                                                              
                         
Eco. Indicators                
                 
Return on Investment (disc) :
   0.000                    
Return on Investment (undisc) :
   0.000   Present Worth Profile (M$)        
Years to Payout :
   0.000                    
Internal Rate of Return (%) :
   0.000   PW 5.00% :   0.000   PW 20.00% :     0.000  
        PW 8.00% :   0.000   PW 30.00% :     0.000  
        PW 10.00% :   0.000   PW 40.00% :     0.000  
        PW 12.00% :   0.000   PW 50.00% :     0.000  
        PW 15.00% :   0.000   PW 60.00% :     0.000  
 
THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. Page 1 of 1 

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ECONOMIC SUMMARY PROJECTION
LEGACY RESERVES GP, LLC
Proved Undeveloped (KM)
Discount Rate: 10.00  
       As of: 7/1/2006
             
Est. Cum Oil Mbbl :
   2,688.279   KINDER MORGAN ACQUISITION    
Est. Cum Gas (MMcf) :
   718.172   June 30, 2006 SEC Pricing    
Est. Cum Water (Mbbl) :
   3,885.862   Plains WTI $70.50/bbl, Platts HH $6.09/ MMBtu    
 
                                                                                                                     
        Oil   Gas   Oil   Gas   Oil   Gas   Oil & Gas   Misc.   Costs   Taxes   Invest.   NonDisc. CF   Cum    
        Gross   Gross   Net   Net   Price   Price   Rev. Net   Rev. Net   Net   Net   Net   Annual   Disc. CF    
    Year   (Mbbl)   (MMcf)   (Mbbl)   (MMcf)   ($/bbl)   ($/Mcf)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)    
 
      2006       0.000       0.000       0.000       0.000       0.00       0.00       0.000       0.000       0.000       0.000       0.000       0.000       0.000      
      2007       17.869       12.508       7.120       4.984       72.21       3.84       533.237       0.000       201.000       43.770       829.500       -541.033       -519.157      
      2008       20.495       14.347       8.166       5.716       72.21       3.84       611.605       0.000       241.200       50.202       0.000       320.203       -254.387      
      2009       19.417       13.592       7.736       5.415       72.21       3.84       579.417       0.000       241.200       47.560       0.000       290.656       -35.924      
      2010       18.446       12.913       7.350       5.145       72.21       3.84       550.465       0.000       241.200       45.184       0.000       264.081       144.535      
      2011       17.525       12.267       6.983       4.888       72.21       3.84       522.960       0.000       241.200       42.926       0.000       238.834       292.917      
      2012       16.694       11.685       6.651       4.656       72.21       3.84       498.156       0.000       241.200       40.890       0.000       216.066       414.958      
      2013       15.815       11.070       6.301       4.411       72.21       3.84       471.939       0.000       241.200       38.738       0.000       192.000       513.533      
      2014       15.025       10.517       5.986       4.190       72.21       3.84       448.357       0.000       241.200       36.803       0.000       170.355       593.052      
      2015       14.274       9.992       5.687       3.981       72.21       3.84       425.954       0.000       241.200       34.964       0.000       149.791       656.621      
      2016       13.597       9.518       5.418       3.792       72.21       3.84       405.751       0.000       241.200       33.305       0.000       131.246       707.265      
      2017       12.881       9.017       5.132       3.593       72.21       3.84       384.397       0.000       241.200       31.552       0.000       111.644       746.422      
      2018       12.238       8.566       4.876       3.413       72.21       3.84       365.190       0.000       241.200       29.976       0.000       94.014       776.402      
      2019       11.626       8.138       4.632       3.243       72.21       3.84       346.943       0.000       241.200       28.478       0.000       77.264       798.805      
      2020       11.075       7.752       4.413       3.089       72.21       3.84       330.487       0.000       241.200       27.127       0.000       62.160       815.197      
 
Rem.
             38.410       26.887       15.304       10.713       72.21       3.84       1,146.206       0.000       949.033       94.084       0.000       103.089       22.874      
Total
     18.5       255.387       178.771       101.756       71.229       72.21       3.84       7,621.065       0.000       4,285.633       625.560       829.500       1,880.371       838.071      
                                                                                         
Ult.     2,943.666       896.943                                                                                              
                         
Eco. Indicators                
                 
Return on Investment (disc) :
   2.075   Present Worth Profile (M$)        
Return on Investment (undisc) :
   3.267                    
Years to Payout :
   3.258   PW 5.00% :   1,244.201   PW 20.00% :     375.297  
Internal Rate of Return (%) :
   39.755   PW 8.00% :   980.432   PW 30.00% :     135.230  
        PW 10.00% :   838.071   PW 40.00% :     -3.249  
        PW 12.00% :   716.643   PW 50.00% :     -89.138  
        PW 15.00% :   565.674   PW 60.00% :     -145.137  
 
THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. Page 1 of 1 

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October 24, 2006
Mr. Kyle McGraw
Legacy Reserves LP
303 W. Wall Street, Suite 1600
Midland, TX 79701
Dear Mr. McGraw:
      At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has estimated the proved reserves and future cash flow, as of June 30, 2006, to the Legacy Reserves LP (Legacy) interest in certain properties located in Mississippi, New Mexico, Oklahoma, and Texas. This report includes certain properties in Justis Field located in Lea County, New Mexico acquired from Henry Holding LP (Henry) in June 2006 and certain properties in Farmer Field located in Crockett and Reagan Counties, Texas which were acquired from Larron Energy Corporation (Larron). Both these acquisitions were effective June 2006. This report does not include certain properties located in New Mexico and Texas which were acquired from Kinder Morgan, Inc. (KM) in July 2006. This report has been prepared using constant prices and costs and conforms to our understanding of the guidelines of the Securities and Exchange Commission (SEC).
      Summarized below are LPC’s estimates of net reserves and future net cash flow. Future net revenue is prior to deducting estimated production and ad valorem taxes. Future net cash flow is after deducting these taxes, operating expenses, and future capital expenditures but before consideration of federal income taxes. The discounted cash flow values included in this report are intended to represent the time value of money and should not be construed to represent an estimate of fair market value. We estimate the proved net reserves and future net cash flow to the Legacy interest, as of June 30, 2006, to be:
                                   
        Future Net Cash Flow ($)
    Net Reserves    
            Present Worth
Category and Entity   Oil (Barrels)   Gas (Mcf)   Total   at 10%
                 
Proved Developed
                                
 
Producing
     10,011,674       26,452,069     $ 489,816,265     $ 242,859,691  
 
Non-Producing
     552,759       1,442,102     $ 36,370,356     $ 13,613,134  
Proved Undeveloped
     2,595,477       5,355,727     $ 107,951,541     $ 34,443,456  
                         
Total Proved(1)
     13,159,910       33,249,898     $ 634,138,162     $ 290,916,281  
 
(1)  The total proved values above may or may not match those values on the summary page that follows this letter due to rounding by the economics program.
      The oil reserves include crude oil and condensate. Oil reserves are expressed in barrels, which are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases.
      The estimated reserves and future cash flow shown in this report are for proved developed producing reserves and, for certain properties, proved developed non-producing and proved undeveloped reserves. 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. Definitions of all reserve categories used in this report are presented immediately following this letter.
      This report includes: (1) summary economic projections of reserves and cash flow for each reserve category, (2) one-line summaries of basic economic data and reserves for each property evaluated, and (3) economic projections of reserves and cash flow for each evaluated property.
      Our estimates of reserves were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from various reservoirs and leases was estimated after

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consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance. In some instances, comparisons were made with similar properties where more complete data were available.
      The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices. The prices on June 30, 2006 were used in the preparation of these estimates as required by SEC guidelines; however, actual future prices may vary significantly from the June 30, 2006 prices. Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this report.
      Oil prices are referenced to a June 30, 2006 West Texas Intermediate (WTI) physical price of $70.50 per barrel, as posted by Plains All American Pipeline, L.P., adjusted for gravity, crude quality, transportation fees, and regional price differentials. Gas prices are referenced to a June 30, 2006 Henry Hub physical price of $6.09 per MMBtu, as published in the Platts Gas Daily, adjusted for energy content, transportation fees, and regional price differentials. Prices are held constant in accordance with SEC guidelines. For reference purposes, the corresponding NYMEX futures contract closing prices for the nearest month contracts being traded on June 30, 2006 were $73.92 per barrel for West Texas Intermediate crude oil and $6.06 per MMBtu for Henry Hub gas.
      Lease and well operating expenses are based on data obtained from Legacy. Lease and well operating costs for the properties operated by Legacy include a per-well overhead expense along with direct lease and field level costs. For properties operated by others, these costs include the per-well overhead expenses allowed under joint operating agreements along with costs estimated to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Legacy are not included. Lease and well operating costs are held constant in accordance with SEC guidelines.
      Capital costs and timing of all investments have been provided by Legacy and are included as required for workovers, new development wells, and production equipment. These costs are also held constant.
      LPC made no investigation of possible oil and gas volume and value imbalances that may have been the result of overdelivery or underdelivery to the Legacy interest. Our projections are based on the Legacy interest receiving its net revenue interest share of estimated future gross oil and gas production.
      Technical information necessary for the preparation of the reserve estimates herein was furnished by Legacy or was obtained from state regulatory agencies and commercially available data sources. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, the individual well test and production data as reported by the above sources were accepted as represented together with all other factual data presented by Legacy including the extent and character of the interest evaluated.
      An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC. Consideration was given to salvage values and abandonment costs for all of the properties. In addition, the costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.
      The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein.
      The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes

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and recovery efficiencies along with analogies to similar production. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data. Therefore, our conclusions represent informed professional judgments only, not statements of fact.
      This report is solely for the use of Legacy, its agents, and its representatives in their evaluation of these properties and is not to be used, circulated, quoted, or otherwise referenced for any other purpose without the express written consent of the undersigned except as required by law. Persons other than those to whom this report is addressed or those authorized by the addressee shall not be entitled to rely upon the report unless it is accompanied by such consent.
      We are independent petroleum engineers, geologists, and geophysicists; we do not own an interest in these properties and are not employed on a contingent basis. Data pertinent to this report are maintained on file in our office.
  Very truly yours,
  LaRoche Petroleum Consultants, Ltd.
 
  /s/ Joe A. Young
 
 
  Joe A. Young
  Senior Partner
  Licensed Professional Engineer
  State of Texas No. 62866
 
  /s/ Al Iakovakis
 
 
  Al Iakovakis
  Senior Staff Engineer

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DEFINITION OF RESERVES
      Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and current regulatory practices. Reserves are considered proved when commercial production has been established by actual production or well tests. The portion of the reservoir considered proved is the area delineated by drilling and reasonable interpretation of available data after considering fluid contacts, if any. Proved reserves may be developed or undeveloped.
      Proved developed producing reserves are those reserves which are expected to be produced from existing completion intervals now open for production in existing wells.
      Proved developed non-producing reserves are (1) those reserves expected to be produced from existing completion intervals in existing wells, but due to pending pipeline connections, regulatory agency considerations, or other mechanical or contractual requirements hydrocarbon sales have not yet commenced or have been interrupted, and (2) other non-producing reserves which exist behind the casing of existing wells, or at minor depths below the present bottom of such wells, which are expected to be produced though these wells in the predictable future, where the cost of making such oil and gas available for production should be moderate when compared to the cost of a new well.
      Proved undeveloped reserves are those reserves which are relatively certain to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required. Undeveloped reserves are considered proved when the interpretation of available geologic information, well test data, and production performance indicate the presence of commercial hydrocarbons that cannot be recovered from presently producing wells. Proved reserves on undrilled acreage are usually limited to proration units that offset wells that have established the existence of commercial quantities of hydrocarbons.

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ECONOMIC SUMMARY PROJECTION
LEGACY RESERVES GP, LLC
Total Proved (excl KM)
Discount Rate: 10.00  
       As of: 7/1/2006
             
Est. Cum Oil Mbbl :
   784,101.320   June 30, 2006 SEC Pricing    
Est. Cum Gas (MMcf) :
   1,648,757.328   Plains WTI $70.50/bbl, Platts HH $6.09/MMBtu    
Est. Cum Water (Mbbl) :
   3,266,979.586   (Excludes Kinder Morgan Acquisition)    
 
                                                                                                                     
        Oil   Gas   Oil   Gas   Oil   Gas   Oil & Gas   Misc.   Costs   Taxes   Invest.   NonDisc. CF   Cum    
        Gross   Gross   Net   Net   Price   Price   Rev. Net   Rev. Net   Net   Net   Net   Annual   Disc. CF    
    Year   (Mbbl)   (MMcf)   (Mbbl)   (MMcf)   ($/bbl)   ($/Mcf)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)    
 
      2006       4,614.465       23,706.899       397.459       1,141.214       69.49       5.35       33,727.003       8.303       6,073.889       2,481.365       10,143.546       15,036.506       14,674.787      
      2007       9,685.044       49,858.992       876.853       2,220.545       69.57       5.33       72,845.186       15.474       12,798.092       5,437.767       9,479.629       45,145.171       55,483.169      
      2008       9,717.677       50,840.045       842.038       2,133.822       69.38       5.31       69,756.878       14.274       12,740.440       5,145.900       10,470.730       41,414.082       89,654.144      
      2009       9,576.949       52,232.174       817.906       2,127.346       69.29       5.40       68,169.893       13.096       12,779.752       5,008.220       10,661.429       39,733.588       119,415.749      
      2010       8,924.604       49,476.276       769.131       1,955.510       69.43       5.41       63,987.170       12.049       12,948.096       4,727.602       10,937.007       35,386.513       143,499.370      
      2011       8,152.584       44,926.279       695.148       1,772.565       69.42       5.39       57,815.051       11.086       12,743.823       4,269.319       155.742       40,657.253       168,767.071      
      2012       7,517.861       40,843.855       634.882       1,610.782       69.38       5.38       52,717.340       10.226       12,540.357       3,890.260       120.840       36,176.110       189,201.890      
      2013       6,827.946       36,410.390       585.585       1,477.433       69.36       5.38       48,559.726       9.382       12,178.509       3,579.015       21.402       32,790.181       206,036.641      
      2014       6,236.914       32,629.244       548.557       1,424.396       69.37       5.37       45,699.122       8.632       11,902.077       3,364.072       18.796       30,422.809       220,232.941      
      2015       5,739.337       29,274.303       513.773       1,315.115       69.36       5.37       42,692.456       7.942       11,685.147       3,136.686       21.001       27,857.564       232,054.851      
      2016       5,305.410       26,678.384       481.755       1,216.801       69.34       5.35       39,922.209       7.326       11,447.606       2,930.549       53.481       25,497.898       241,890.608      
      2017       4,896.687       24,010.024       450.542       1,117.418       69.34       5.36       37,225.153       6.721       11,102.305       2,728.504       30.236       23,370.830       250,085.901      
      2018       4,519.850       21,734.235       422.699       1,035.900       69.33       5.36       34,862.617       6.184       10,861.937       2,550.955       13.650       21,442.259       256,921.222      
      2019       4,182.303       19,789.223       395.571       978.716       69.32       5.37       32,674.442       5.689       10,506.791       2,388.451       18.518       19,766.371       262,649.827      
      2020       3,880.625       18,103.857       372.488       918.298       69.31       5.36       30,741.091       5.248       10,211.877       2,244.250       45.764       18,244.448       267,456.533      
 
Rem.
             45,828.740       193,755.094       4,355.522       10,804.040       69.52       5.39       360,996.997       25.619       151,624.569       26,549.797       1,408.671       181,439.580       23,695.995      
Total
     50.0       145,606.996       714,269.275       13,159.910       33,249.898       69.43       5.37       1,092,392.334       167.250       324,145.267       80,432.713       53,600.442       634,381.163       291,152.528      
                                                                                         
Ult.     929,708.316       2,363,026.602                                                                                              
                         
Eco. Indicators                
                 
Return on Investment (disc) :
   7.699                    
Return on Investment (undisc) :
   12.835   Present Worth Profile (M$)        
Years to Payout :
   1.016                    
Internal Rate of Return(%) :
   >1000.0   PW 5.00% :   401,477.612   PW 20.00% :     187,848.182  
        PW 8.00% :   327,248.830   PW 30.00% :     139,471.861  
        PW 10.00% :   291,152.528   PW 40.00% :     111,666.876  
        PW 12.00% :   262,197.235   PW 50.00% :     93,687.129  
        PW 15.00% :   228,198.367   PW 60.00% :     81,131.305  
 
THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. Page 1 of 1 

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ECONOMIC SUMMARY PROJECTION
LEGACY RESERVES GP, LLC
Proved Undeveloped (excl KM)
Discount Rate: 10.00  
       As of: 7/1/2006
             
Est. Cum Oil Mbbl :
   0.000   June 30, 2006 SEC Pricing    
Est. Cum Gas (MMcf) :
   0.000   Plains WTI $70.50/bbl, Platts HH $6.09/MMBtu    
Est. Cum Water (Mbbl) :
   0.000   (Excludes Kinder Morgan Acquisition)    
 
                                                                                                                     
        Oil   Gas   Oil   Gas   Oil   Gas   Oil & Gas   Misc.   Costs   Taxes   Invest.   NonDisc. CF   Cum    
        Gross   Gross   Net   Net   Price   Price   Rev. Net   Rev. Net   Net   Net   Net   Annual   Disc. CF    
    Year   (Mbbl)   (MMcf)   (Mbbl)   (MMcf)   ($/bbl)   ($/Mcf)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)    
 
      2006       51.305       513.612       14.678       33.167       71.62       5.86       1,245.416       0.000       125.834       104.262       9,441.413       -8,426.092       -8,226.922      
      2007       656.831       2,535.849       153.467       202.688       70.41       5.38       11,896.241       0.000       761.590       965.854       8,705.409       1,463.388       -7,153.792      
      2008       1,142.902       5,013.575       174.466       301.694       69.52       5.24       13,708.673       0.000       826.303       1,036.679       10,146.393       1,699.298       -5,822.798      
      2009       1,649.536       9,537.038       201.769       471.420       69.20       5.73       16,666.188       0.000       1,038.442       1,240.855       10,434.056       3,952.836       -2,958.662      
      2010       1,730.712       11,145.616       196.537       433.875       69.79       5.81       16,238.848       0.000       1,324.613       1,242.517       10,936.232       2,735.487       -1,189.890      
      2011       1,631.837       10,724.402       162.463       367.059       69.81       5.79       13,466.527       0.000       1,362.724       1,039.830       0.000       11,063.973       5,695.183      
      2012       1,549.678       10,326.400       135.987       306.371       69.72       5.80       11,257.855       0.000       1,351.828       876.725       0.000       9,029.302       10,797.413      
      2013       1,407.588       9,231.784       120.816       269.834       69.69       5.82       9,990.702       0.000       1,320.697       778.145       0.000       7,891.860       14,850.076      
      2014       1,277.210       8,116.240       110.400       244.043       69.68       5.85       9,119.587       0.000       1,290.776       708.677       0.000       7,120.135       18,173.842      
      2015       1,165.139       7,179.217       101.809       222.629       69.68       5.87       8,401.077       0.000       1,274.661       651.455       0.000       6,474.962       20,921.677      
      2016       1,072.148       6,401.480       94.683       204.725       69.68       5.90       7,805.367       0.000       1,258.946       604.295       0.000       5,942.126       23,213.934      
      2017       986.409       5,708.317       87.963       188.063       69.69       5.93       7,244.899       0.000       1,249.183       560.254       0.000       5,435.462       25,119.912      
      2018       911.441       5,131.310       81.893       173.786       69.71       5.96       6,744.110       0.000       1,227.608       521.224       0.000       4,995.278       26,712.440      
      2019       844.450       4,630.753       76.254       160.904       69.75       5.98       6,281.348       0.000       1,204.496       485.019       0.000       4,591.833       28,043.244      
      2020       789.895       4,207.074       71.956       150.107       69.77       6.01       5,922.260       0.000       1,201.287       457.172       0.000       4,263.802       29,166.577      
 
Rem.
             10,788.455       45,900.385       810.335       1,625.363       70.31       6.34       67,282.599       0.000       21,961.305       5,302.466       57.936       39,960.892       5,513.126      
Total
     50.0       27,655.535       146,303.051       2,595.477       5,355.727       69.91       5.94       213,271.698       0.000       38,780.290       16,575.428       49,721.438       108,194.541       34,679.703      
                                                                                         
Ult.     27,655.535       146,303.051                                                                                              
                         
Eco. Indicators                
                 
Return on Investment (disc) :
   1.841                    
Return on Investment (undisc) :
   3.176   Present Worth Profile (M$)        
Years to Payout :
   4.408                    
Internal Rate of Return (%) :
   41.943   PW 5.00% :   58,199.299   PW 20.00% :     13,823.912  
        PW 8.00% :   42,301.933   PW 30.00% :     5,052.964  
        PW 10.00% :   34,679.703   PW 40.00% :     579.956  
        PW 12.00% :   28,655.868   PW 50.00% :     -1,973.102  
        PW 15.00% :   21,732.384   PW 60.00% :     -3,542.209  
 
THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. Page 1 of 1 

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ECONOMIC SUMMARY PROJECTION
LEGACY RESERVES GP, LLC
Proved Developed Producing (excl KM)
Discount Rate: 10.00  
       As of: 7/1/2006
             
Est. Cum Oil Mbbl :
   771,759.664   June 30, 2006 SEC Pricing    
Est. Cum Gas (MMcf) :
   1,607,434.527   Plains WTI $70.50/bbl, Platts HH $6.09/ MMBtu    
Est. Cum Water (Mbbl) :
   3,252,951.413   (Excludes Kinder Morgan Acquisition)    
 
                                                                                                                     
                                Oil &                            
        Oil   Gas   Oil   Gas   Oil   Gas   Gas   Misc.   Costs   Taxes   Invest.   NonDisc. CF   Cum    
        Gross   Gross   Net   Net   Price   Price   Rev. Net   Rev. Net   Net   Net   Net   Annual   Disc. CF    
    Year   (Mbbl)   (MMcf)   (Mbbl)   (MMcf)   ($/bbl)   ($/Mcf)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)    
 
      2006       4,422.495       20,697.255       374.222       1,077.800       69.37       5.30       31,675.613       8.303       5,876.674       2,313.538       82.641       23,411.064       22,861.083      
      2007       8,006.645       36,128.330       687.305       1,911.226       69.35       5.29       57,763.209       15.474       11,652.318       4,207.529       23.095       41,895.740       60,982.962      
      2008       7,080.813       30,727.731       631.076       1,730.112       69.33       5.27       52,877.231       14.274       11,487.544       3,839.364       0.337       37,564.260       92,050.733      
      2009       6,311.253       26,720.242       581.805       1,571.539       69.32       5.26       48,603.014       13.096       11,328.598       3,520.372       11.373       33,755.767       117,425.784      
      2010       5,692.993       23,618.438       541.646       1,448.780       69.31       5.26       45,155.872       12.049       11,230.501       3,264.656       0.776       30,671.989       138,387.213      
      2011       5,142.618       21,031.411       505.300       1,342.392       69.30       5.25       42,064.918       11.086       11,014.793       3,035.739       45.900       27,979.571       155,770.208      
      2012       4,695.215       18,932.051       473.965       1,248.206       69.29       5.24       39,389.454       10.226       10,842.759       2,838.227       119.366       25,599.328       170,228.647      
      2013       4,248.954       17,029.363       441.937       1,158.099       69.28       5.24       36,686.673       9.382       10,543.755       2,641.896       21.402       23,489.003       182,287.159      
      2014       3,870.418       15,399.151       414.644       1,066.932       69.27       5.23       34,307.501       8.632       10,309.843       2,465.871       1.596       21,538.823       192,340.626      
      2015       3,564.455       14,034.296       390.062       986.678       69.27       5.23       32,174.258       7.942       10,116.693       2,308.785       3.705       19,753.017       200,722.505      
      2016       3,295.413       12,884.628       367.604       925.723       69.26       5.22       30,290.151       7.326       9,903.444       2,171.253       39.694       18,183.087       207,736.324      
      2017       3,041.397       11,795.340       345.095       863.829       69.25       5.22       28,404.059       6.721       9,583.325       2,034.017       30.236       16,763.201       213,614.361      
      2018       2,799.388       10,839.416       325.437       810.189       69.24       5.22       26,761.190       6.184       9,441.004       1,913.317       8.605       15,404.449       218,524.711      
      2019       2,582.977       10,039.981       306.156       776.939       69.23       5.21       25,246.592       5.689       9,227.882       1,803.971       18.518       14,201.910       222,640.650      
      2020       2,380.796       9,310.323       288.191       731.406       69.22       5.20       23,752.537       5.248       8,948.122       1,694.801       29.696       13,085.166       226,088.284      
 
Rem.
             23,773.332       107,623.206       3,337.226       8,802.217       69.34       5.18       276,974.267       25.619       129,845.892       19,820.130       813.974       126,519.890       16,771.408      
Total
     50.0       90,909.163       386,811.163       10,011.674       26,452.069       69.31       5.22       832,126.539       167.250       281,353.146       59,873.465       1,250.912       489,816.265       242,859.691      
                                                                                         
Ult.     862,668.827       1,994,245.690                                                                                              
                         
Eco. Indicators                
                 
Return on Investment (disc) :
   718.321                    
Return on Investment (undisc) :
   392.567   Present Worth Profile (M$)        
Years to Payout :
   0.027                    
Internal Rate of Return(%) :
   >1000.0   PW 5.00% :   323,390.780   PW 20.00% :     165,711.136  
        PW 8.00% :   269,368.444   PW 30.00% :     128,484.009  
        PW 10.00% :   242,859.691   PW 40.00% :     106,499.169  
        PW 12.00% :   221,455.250   PW 50.00% :     91,936.093  
        PW 15.00% :   196,127.447   PW 60.00% :     81,548.619  
 
THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. Page 1 of 1 

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ECONOMIC SUMMARY PROJECTION
LEGACY RESERVES GP, LLC
Proved Dev Non-Producing (excl KM)
Discount Rate: 10.00  
       As of: 7/1/2006
             
Est. Cum Oil Mbbl :
   12,515.943   June 30, 2006 SEC Pricing    
Est. Cum Gas (MMcf) :
   41,356.278   Plains WTI $70.50/bbl, Platts HH $6.09/ MMBtu    
Est. Cum Water (Mbbl) :
   20,387.073   (Excludes Kinder Morgan Acquisition)    
 
                                                                                                                     
        Oil   Gas   Oil   Gas   Oil   Gas   Oil & Gas   Misc.   Costs   Taxes   Invest.   NonDisc. CF   Cum    
        Gross   Gross   Net   Net   Price   Price   Rev. Net   Rev. Net   Net   Net   Net   Annual   Disc. CF    
    Year   (Mbbl)   (MMcf)   (Mbbl)   (MMcf)   ($/bbl)   ($/Mcf)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)   (M$)    
 
      2006       140.665       2,496.032       8.559       30.247       71.28       6.48       805.973       0.000       71.381       63.566       619.493       51.534       40.626      
      2007       1,021.569       11,194.813       36.080       106.631       70.30       6.09       3,185.736       0.000       384.185       264.383       751.125       1,786.043       1,653.999      
      2008       1,493.963       15,098.739       36.496       102.016       69.59       6.19       3,170.974       0.000       426.592       269.857       324.000       2,150.524       3,426.209      
      2009       1,616.160       15,974.893       34.332       84.387       69.32       6.17       2,900.691       0.000       412.712       246.993       216.000       2,024.986       4,948.628      
      2010       1,500.898       14,712.222       30.948       72.854       69.26       6.16       2,592.449       0.000       392.983       220.430       0.000       1,979.036       6,302.047      
      2011       1,378.129       13,170.467       27.385       63.114       69.21       6.15       2,283.606       0.000       366.306       193.750       109.842       1,613.709       7,301.680      
      2012       1,272.968       11,585.404       24.929       56.205       69.19       6.14       2,070.032       0.000       345.770       175.308       1.474       1,547.480       8,175.831      
      2013       1,171.404       10,149.243       22.831       49.499       69.18       6.12       1,882.351       0.000       314.058       158.974       0.000       1,409.319       8,899.407      
      2014       1,089.285       9,113.854       23.512       113.421       69.51       5.62       2,272.034       0.000       301.458       189.525       17.200       1,763.851       9,718.474      
      2015       1,009.743       8,060.790       21.903       105.808       69.52       5.62       2,117.121       0.000       293.794       176.446       17.296       1,629.585       10,410.669      
      2016       937.850       7,392.276       19.468       86.353       69.38       5.51       1,826.691       0.000       285.217       155.001       13.788       1,372.685       10,940.350      
      2017       868.880       6,506.367       17.484       65.526       69.28       5.57       1,576.195       0.000       269.797       134.232       0.000       1,172.167       11,351.628      
      2018       809.021       5,763.509       15.369       51.924       69.12       5.68       1,357.317       0.000       193.325       116.414       5.045       1,042.532       11,684.071      
      2019       754.876       5,118.489       13.160       40.873       68.89       5.87       1,146.503       0.000       74.413       99.462       0.000       972.628       11,965.933      
      2020       709.934       4,586.461       12.342       36.785       68.87       5.88       1,066.293       0.000       62.468       92.277       16.068       895.480       12,201.672      
 
Rem.
             11,266.954       40,231.502       207.961       376.460       69.29       6.19       16,740.131       0.000       -182.628       1,427.201       536.761       14,958.797       1,411.461      
Total
     50.0       27,042.298       181,155.061       552.759       1,442.102       69.39       5.99       46,994.098       0.000       4,011.830       3,983.820       2,628.092       36,370.356       13,613.134      
                                                                                         
Ult.     39,558.241       222,511.339                                                                                              
                         
Eco. Indicators                
                 
Return on Investment (disc) :
   8.299   Present Worth Profile (M$)        
Return on Investment (undisc) :
   14.839                    
Years to Payout :
   1.273   PW 5.00% :   19,887.532   PW 20.00% :     8,313.134  
Internal Rate of Return(%) :
   >1000.0   PW 8.00% :   15,578.453   PW 30.00% :     5,934.887  
        PW 10.00% :   13,613.134   PW 40.00% :     4,587.751  
        PW 12.00% :   12,086.117   PW 50.00% :     3,724.139  
        PW 15.00% :   10,338.536   PW 60.00% :     3,124.895  
 
THESE DATA ARE PART OF A LAROCHE PETROLEUM CONSULTANTS, LTD. REPORT AND ARE SUBJECT TO THE CONDITIONS IN THE TEXT OF THE REPORT. Page 1 of 1 

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(LEGACY RESERVES LOGO)
Legacy Reserves LP
4,209,954 Units
Representing Limited Partner Interests
 
PROSPECTUS
 
                        , 2006
       Until                     , 2006 (25 days after the commencement of this offering), all dealers that effect transactions in our units, whether or not participating in this offering, may be required to deliver a prospectus.

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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 sale of the securities registered hereby. The selling unitholders will not bear any portion of such expenses. With the exception of the Securities and Exchange Commission registration fee and the NASD filing fee, the amounts set forth below are estimates.
           
SEC registration fee
   $ 7,658  
NASD filing fee
     7,657  
Printing and engraving expenses
     150,000  
Accounting fees and expenses
     110,000  
Legal fees and expenses
     150,000  
Miscellaneous
     5,685  
       
 
Total
   $ 431,000  
 
*  To be provided by amendment.
Item 14. Indemnification of Directors and Officers.
      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. Reference is also made to Section 6 of the Registration Rights Agreement to be filed as an exhibit to this registration statement in which we have agreed to indemnify the selling unitholders against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. 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.
      We have obtained directors’ and officers’ insurance to cover our director, officers and some of our employees for certain liabilities.
      To the extent that the indemnification provisions of our partnership agreement purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.
Item 15. Recent Sales of Unregistered Securities.
      1. In October 2005, in connection with the formation of Legacy Reserves LP, we issued to Moriah Resources, Ltd. the 99.9% limited partner interest in Legacy Reserves LP for $999.00. The issuance was exempt from registration under Section 4(2) of the Securities Act because the transaction did not involve a public offering.
      2. In connection with our formation transactions, on March 15, 2006, we issued units to our Founding Investors contributing oil and natural gas properties and related assets to us. The issuances of the units described below was exempt from registration under Section 4(2) of the Securities Act because the issuances

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did not involve a public offering. The following table summarizes the issuance of our units in the formation transactions:
           
    Units
     
Moriah Group:
        
 
Moriah Properties, Ltd. 
     7,334,070  
 
DAB Resources, Ltd. 
     859,703  
Brothers Group:
        
 
Brothers Production Properties, Ltd
     4,968,945  
 
Brothers Production Company, Inc. 
     264,306  
 
Brothers Operating Company, Inc. 
     52,861  
 
J&W McGraw Properties, Ltd. 
     914,246  
MBN Properties LP
     3,162,438  
H2K Holdings, Ltd. 
     83,499  
      3. On March 15, 2006, we issued 52,616 restricted units in the aggregate to certain members of management pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuances of these units were exempt from the registration requirements of the Securities Act pursuant to Rule 701.
      4. On March 15, 2006, we issued 5,000,000 units in consideration of $85,000,000 before the initial purchaser’s discount, placement agent’s fees and expense to qualified institutional investors and accredited investors in transactions exempt from registration under Section 4(2) of the Securities Act. We paid Friedman, Billings, Ramsey & Co., Inc., who acted as placement agent and initial purchaser in this transaction $5,950,000 in initial purchaser’s discount and placement agent’s fees.
      5. On May 1, 2006, we issued 8,750 units in the aggregate to certain of the directors of our general partner pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuances of these units were exempt from the registration requirements of the Securities Act pursuant to Rule 701.
      6. On May 5, 2006, we issued 12,500 restricted units to an employee pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuances of these units and options were exempt from the registration requirements of the Securities Act pursuant to Rule 701.
      7. On June 29, 2006, and November 10, 2006 we issued 138,000 units and 8,415 units, respectively, to Henry Holding LP as partial consideration for our acquisition of oil and natural gas producing properties located in Lea County New Mexico and contract operating rights for total consideration of approximately $13.4 million cash and 146,415 units. The issuances of these units were exempt from registration under Section 4(2) of the Securities Act because the issuances did not involve a public offering.
      8. On July 17, 2006, we issued options to purchase 251,000 units to employees and officers pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuance of these options were exempt from the registration requirements of the Securities Act pursuant to Rule 701.
      9. On September 15, 2006, we issued options to purchase 10,000 units to an employee pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuance of these options was exempt from the registration requirements of the Securities Act pursuant to Rule 701.
      10. On October 10, 2006 we issued options to purchase 12,000 units to employees pursuant to the Legacy Reserves LP Long-Term Incentive Plan. The issuance of these options was exempt from the registration requirements of the Securities Act pursuant to Rule 701.

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Item 16. Exhibits and Financial Statement Schedules.
      (a) The following documents are filed as exhibits to this registration statement:
             
Exhibit        
Number       Description
         
  3 .1**   —   Certificate of Limited Partnership of Legacy Reserves LP
  3 .2**   —   Amended and Restated Limited Partnership Agreement of Legacy Reserves LP (included as Appendix A to the Prospectus and including specimen unit certificate for the units)
  3 .3**   —   Certificate of Formation of Legacy Reserves GP, LLC
  3 .4**   —   Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC
  4 .1**   —   Registration Rights Agreement dated as of March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and Friedman, Billings, Ransey & Co.
  4 .2**   —   Registration Rights Agreement dated June 29, 2006 between Henry Holding LP and Legacy Reserves LP and Legacy Reserves GP, LLC (the “Henry Registration Rights Agreement”)
  4 .3**   —   Registration Rights Agreement dated March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto (the “Founders Registration Rights Agreement”)
  5 .1**   —   Form of opinion of Andrews Kurth LLP as to the legality of the securities being registered
  8 .1**   —   Form of opinion of Andrews Kurth LLP relating to tax matters
  10 .1**   —   Credit Agreement dated as of March 15, 2006, among Legacy Reserves LP, the lenders from time to time party thereto, and BNP Paribas, as administrative agent
  10 .2**   —   Contribution, Conveyance and Assumption Agreement dated as of March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto
  10 .3**   —   Omnibus Agreement dated as of March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto
  10 .4**   —   Purchase/Placement Agreement dated as of March 6, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto
  10 .5**   —   Legacy Reserves, LP Long-Term Incentive Plan
  10 .6**   —   Form of Legacy Reserves LP Long-Term Incentive Plan Restricted Unit Grant Agreement
  10 .7**   —   Form of Legacy Reserves LP Long-Term Incentive Plan Unit Option Grant Agreement
  10 .8**   —   Form of Legacy Reserves LP Long-Term Incentive Plan Unit Grant Agreement
  10 .9**   —   Employment Agreement dated as of March 15, 2006 between Carey D. Brown and Legacy Reserves Services, Inc.
  10 .10**   —   Employment Agreement dated as of March 15, 2006 between Steven H. Pruett and Legacy Reserves Services, Inc.
  10 .11**   —   Employment Agreement dated as of March 15, 2006 between Kyle A. McGraw and Legacy Reserves Services, Inc.
  10 .12**   —   Employment Agreement dated as of March 15, 2006 between Paul T. Horne and Legacy Reserves Services, Inc.
  10 .13**   —   Employment Agreement dated as of March 15, 2006 between William M. Morris and Legacy Reserves Services, Inc.
  10 .14**   —   First Amendment to Credit Agreement effective as of July 7, 2006 among Legacy Reserves LP, the lenders from time to time party thereto, and BNP Paribas, as administrative agent.
  10 .15**   —   Purchase and Sale Agreement dated June 29, 2006 between Kinder Morgan Production Company LP and Legacy Reserves Operating LP
  10 .16**   —   Purchase and Sale Agreement dated June 13, 2006 between Henry Holding LP and Legacy Reserves Operating LP
  10 .17**   —   First Amendment of Legacy Reserves LP to Long Term Incentive Plan dated June 16, 2006
  21 .1**   —   List of subsidiaries of Legacy Reserves LP
  23 .1   —   Consent of BDO Seidman, LLP
  23 .2   —   Consent of Johnson Miller & Co., CPA’s PC
  23 .3   —   Consent of LaRoche Petroleum Consultants, Ltd.
  23 .4*   —   Consent of Andrews Kurth LLP (contained in Exhibit 5.1)

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Exhibit        
Number       Description
         
  23 .5*   —   Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
  24 .1**   —   Powers of Attorney
 
  *  To be filed by amendment.
**  Previously filed.
Item 17. Undertakings.
      (a) The undersigned registrant hereby undertakes:
        (1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:
        (i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933, as amended;
 
        (ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement; and
 
        (iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;
        (2) That, for the purpose of determining any liability under the Securities Act of 1933, as amended, each such 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.
 
        (3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
      (b) 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 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 of 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

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  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.

      The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
      The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

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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 November 10, 2006.
  LEGACY RESERVES LP
  By: LEGACY RESERVES GP, LLC,
  its general partner
  By:  /s/ Steven H. Pruett
 
 
  Name:  Steven H. Pruett
  Title: President, Chief Financial Officer
  and Secretary
      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 indicated.
             
Signature   Title   Date
         
 
*
 
Cary D. Brown		   Chief Executive Officer
and Director (Principal
Executive Officer)		   November 10, 2006
 
/s/ Steven H. Pruett
 
Steven H. Pruett		   President, Chief
Financial Officer and Secretary
(Principal Financial Officer)		   November 10, 2006
 
*
 
William M. Morris		   Vice President, Chief Accounting
Officer and Controller (Principal
Accounting Officer)		   November 10, 2006
 
*
 
Kyle A. McGraw		   Executive Vice President and Director   November 10, 2006
 
*
 
Dale A. Brown		   Director   November 10, 2006
 
*
 
G. Larry Lawrence		   Director   November 10, 2006
 
*
 
William D. Sullivan		   Director   November 10, 2006
 
 *
 
S. Wil VanLoh, Jr.		   Director   November 10, 2006

II-6

Table of Contents

             
Signature   Title   Date
         
 
*
 
Kyle D. Vann		   Director   November 10, 2006
 
*By:   /s/ Steven H. Pruett
 
Steven H. Pruett
Attorney-in-Fact		        

II-7

Table of Contents

EXHIBIT INDEX
             
Exhibit        
Number       Description
         
  3 .1**   —   Certificate of Limited Partnership of Legacy Reserves LP
  3 .2**   —   Amended and Restated Limited Partnership Agreement of Legacy Reserves LP (included as Appendix A to the Prospectus and including specimen unit certificate for the units)
  3 .3**   —   Certificate of Formation of Legacy Reserves GP, LLC
  3 .4**   —   Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC
  4 .1**   —   Registration Rights Agreement dated as of March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and Friedman, Billings, Ransey & Co.
  4 .2**   —   Registration Rights Agreement dated June 29, 2006 between Henry Holding LP and Legacy Reserves LP and Legacy Reserves GP, LLC (the “Henry Registration Rights Agreement”)
  4 .3**   —   Registration Rights Agreement dated March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto (the “Founders Registration Rights Agreement”)
  5 .1**   —   Form of opinion of Andrews Kurth LLP as to the legality of the securities being registered
  8 .1**   —   Form of opinion of Andrews Kurth LLP relating to tax matters
  10 .1**   —   Credit Agreement dated as of March 15, 2006, among Legacy Reserves LP, the lenders from time to time party thereto, and BNP Paribas, as administrative agent
  10 .2**   —   Contribution, Conveyance and Assumption Agreement dated as of March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto
  10 .3**   —   Omnibus Agreement dated as of March 15, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto
  10 .4**   —   Purchase/Placement Agreement dated as of March 6, 2006 by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto
  10 .5**   —   Legacy Reserves, LP Long-Term Incentive Plan
  10 .6**   —   Form of Legacy Reserves LP Long-Term Incentive Plan Restricted Unit Grant Agreement
  10 .7**   —   Form of Legacy Reserves LP Long-Term Incentive Plan Unit Option Grant Agreement
  10 .8**   —   Form of Legacy Reserves LP Long-Term Incentive Plan Unit Grant Agreement
  10 .9**   —   Employment Agreement dated as of March 15, 2006 between Carey D. Brown and Legacy Reserves Services, Inc.
  10 .10**   —   Employment Agreement dated as of March 15, 2006 between Steven H. Pruett and Legacy Reserves Services, Inc.
  10 .11**   —   Employment Agreement dated as of March 15, 2006 between Kyle A. McGraw and Legacy Reserves Services, Inc.
  10 .12**   —   Employment Agreement dated as of March 15, 2006 between Paul T. Horne and Legacy Reserves Services, Inc.
  10 .13**   —   Employment Agreement dated as of March 15, 2006 between William M. Morris and Legacy Reserves Services, Inc.
  10 .14**   —   First Amendment to Credit Agreement effective as of July 7, 2006 among Legacy Reserves LP, the lenders from time to time party thereto, and BNP Paribas, as administrative agent.
  10 .15**   —   Purchase and Sale Agreement dated June 29, 2006 between Kinder Morgan Production Company LP and Legacy Reserves Operating LP
  10 .16**   —   Purchase and Sale Agreement dated June 13, 2006 between Henry Holding LP and Legacy Reserves Operating LP
  10 .17**   —   First Amendment of Legacy Reserves LP to Long Term Incentive Plan dated June 16, 2006
  21 .1**   —   List of subsidiaries of Legacy Reserves LP
  23 .1   —   Consent of BDO Seidman, LLP

Table of Contents

             
Exhibit        
Number       Description
         
  23 .2   —   Consent of Johnson Miller & Co., CPA’s PC
  23 .3   —   Consent of LaRoche Petroleum Consultants, Ltd.
  23 .4*   —   Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
  23 .5*   —   Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
  24 .1**   —   Powers of Attorney
 
  *  To be filed by amendment.
**  Previously filed.