424B1 1 h75980b1e424b1.htm 424B1 e424b1
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Filed Pursuant to Rule 424(b)(1)
Registration No. 333-169664
PROSPECTUS
 
(QR ENERGY LOGO)
QR Energy, LP
15,000,000 Common Units
Representing Limited Partner Interests
 
We are a Delaware limited partnership formed by affiliates of Quantum Resource Funds to own and acquire producing oil and natural gas properties. In exchange for conveying certain producing oil and natural gas properties to us, Quantum Resource Funds will be entitled to receive, either directly or through our assumption of its indebtedness, all of the net proceeds of this offering, including any net proceeds from the exercise of the underwriters’ option to purchase additional common units. This is the initial public offering of our common units. No public market currently exists for our common units. We have been approved to list our common units on the New York Stock Exchange, subject to official notice of issuance, under the symbol “QRE”.
Investing in our common units involves risks. Please read “Risk Factors” beginning on page 29.
 
These risks include the following:
 
  •  We may not have sufficient cash flow from operations to pay the minimum quarterly distribution on our common units. We would not have generated sufficient available cash on a pro forma basis to have paid the minimum quarterly distribution on all of our units for the year ended December 31, 2009 or the twelve months ended September 30, 2010.
 
  •  Our estimated oil and natural gas reserves will naturally decline over time, and we may be unable to sustain distributions at the level of our minimum quarterly distribution.
 
  •  Oil and natural gas prices are very volatile and a decline in oil or natural gas prices could cause us to reduce our distributions or cease paying distributions altogether.
 
  •  Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us.
 
  •  The Fund, Quantum Energy Partners and other affiliates of our general partner will not be limited in their ability to compete with us.
 
  •  Neither we nor our general partner have any employees, and we rely solely on the employees of Quantum Resources Management to manage our business.
 
  •  The management incentive fee we will pay to our general partner may increase in situations where there is no corresponding increase in distributions to our common unitholders.
 
  •  If our general partner converts a portion of its management incentive fee in respect of a quarter into Class B units, it will be entitled to receive pro rata distributions on those Class B units.
 
  •  Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors.
 
  •  Our unitholders will experience immediate and substantial dilution of $15.56 per unit.
 
  •  Our tax treatment depends on our status as a partnership for federal income tax purposes.
 
  •  Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
 
  •  Units held by persons who our general partner determines are not Eligible Holders will be subject to redemption.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
 
                 
    Per Common Unit
  Total
   
 
Public offering price
  $ 20.00     $ 300,000,000  
Underwriting discount(1)
  $ 1.30     $ 19,500,000  
Proceeds, before expenses, to QR Energy, LP
  $ 18.70     $ 280,500,000  
 
(1)Excludes an aggregate structuring fee equal to 0.25% of the gross proceeds of this offering, or $750,000, payable to Wells Fargo Securities, LLC.
 
We have granted the underwriters a 30-day option to purchase up to an additional 2,250,000 common units on the same terms and conditions as set forth above if the underwriters sell more than 15,000,000 common units in this offering.
 
The underwriters expect to deliver the common units on or about December 22, 2010.
 
Joint Book-Running Managers
Wells Fargo Securities  
  J.P. Morgan  
  Raymond James  
  RBC Capital Markets
Co-Managers
Baird  
  Credit Suisse  
  Deutsche Bank Securities  
  Oppenheimer & Co.  
  Stifel Nicolaus Weisel
 
Prospectus dated December 16, 2010


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You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.
 
Until January 10, 2011 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
 
 
This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” beginning on page 29 and “Forward-Looking Statements” on page 250.
 
Industry and Market Data
 
The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.


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PROSPECTUS SUMMARY
 
This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including “Risk Factors” beginning on page 29 and the historical and unaudited pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes that the underwriters do not exercise their option to purchase up to an additional 2,250,000 common units and that, instead, the additional 2,250,000 common units will be issued to the Fund upon expiration of such option, unless otherwise indicated. As used in this prospectus, unless we indicate otherwise:
 
  •  “QR Energy,” “the partnership,” “we,” “our,” “us” or like terms refer collectively to QR Energy, LP and its subsidiaries;
 
  •  “our general partner” refers to QRE GP, LLC;
 
  •  “the Fund” or “Quantum Resource Funds” refer collectively to Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP, and Black Diamond Resources, LLC;
 
  •  “our predecessor” refers to QA Holdings, LP, our predecessor for accounting purposes and the indirect owner of the general partner interests of the limited partnerships comprising the Fund;
 
  •  “Quantum Energy Partners” refers collectively to Quantum Energy Partners, LLC, its affiliated private equity funds and their respective portfolio investments;
 
  •  “Quantum Resources Management” refers to Quantum Resources Management, LLC, the entity that provides certain administrative and operational services to both us and the Fund and employs all of our general partner’s officers;
 
  •  “Partnership Properties” or “our properties” refers to the properties and related oil and natural gas interests to be contributed to us by the Fund in connection with this offering; and
 
  •  “Denbury Acquisition” refers to the Fund’s acquisition of approximately $893 million of oil and natural gas properties, which we refer to as the “Denbury Assets,” from Denbury Resources Inc. in May 2010.
 
Unless we indicate otherwise, our financial and reserve information in this prospectus is presented on a pro forma basis as if this offering and the other transactions contemplated by this prospectus, including the Fund’s contribution of the Partnership Properties to us, and the Denbury Acquisition had occurred on January 1, 2009. We include a glossary of some of the oil and natural gas terms used in this prospectus in Appendix B. Our pro forma estimated proved reserve information as of December 31, 2009 is based on evaluations prepared by our internal reserve engineers. Our pro forma estimated proved reserve information as of June 30, 2010 is based on a report prepared by Miller and Lents, Ltd., our independent reserve engineers. A summary of our pro forma estimated proved reserve information as of June 30, 2010 prepared by Miller and Lents, Ltd. is included in this prospectus in Appendix C.
 
QR Energy, LP
 
Overview
 
We are a Delaware limited partnership formed by affiliates of the Fund to own and acquire producing oil and natural gas properties in North America. Our properties consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, predictable production profiles. For a discussion of the principal characteristics of our properties, please read “Business and Properties — Properties” on page 148. As of June 30, 2010, our total estimated proved reserves were approximately 29.7 MMBoe, of which approximately 69% were oil and NGLs and 68% were classified as proved developed reserves. As of June 30, 2010, we operated 83% of our assets, as measured by value, based on the estimated future net


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revenues discounted at 10% of our estimated proved reserves, or standardized measure. Our estimated proved reserves had standardized measure of $467.3 million as of June 30, 2010. Based on our pro forma average net production for the nine months ended September 30, 2010 of 5,184 Boe/d, our total estimated proved reserves had a reserve-to-production ratio of 15.7 years.
 
We believe our business relationship with the Fund enhances our ability to grow our estimated proved reserves over time. The Fund is a collection of limited partnerships formed by the founders of Quantum Energy Partners and Don Wolf, the Chairman of the Board of our general partner, for the purpose of acquiring mature, legacy producing oil and natural gas properties with similar characteristics to the Partnership Properties. After giving effect to its contribution of the Partnership Properties to us, the Fund had total estimated proved reserves of 56.4 MMBoe, of which approximately 76% were classified as proved developed reserves, with standardized measure of $630.5 million as of June 30, 2010, and interests in over 1,000 gross (630 net) oil and natural gas wells, with pro forma average net production of approximately 13,132 Boe/d for the nine months ended September 30, 2010. We believe that the majority of the Fund’s retained assets are currently suitable for acquisition by us, based on our criteria that properties consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, predictable production profiles. The Fund has informed us that it intends to offer us the opportunity to purchase these mature onshore producing oil and natural gas assets, from time to time, in future periods. The Fund has no obligation to sell properties to us following the consummation of this offering, and except as provided in the omnibus agreement, the Fund has no obligation to offer additional properties to us following the consummation of this offering. For a discussion of our future acquisition opportunities with the Fund and its affiliates, please read “— Our Principal Business Relationships” on page 146.
 
Our Properties
 
Our properties are located across four diverse producing regions and consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, predictable production profiles. Approximately 72% of our estimated reserves as measured by value, based on standardized measure, have had associated production since 1970. As of June 30, 2010, we produced from 2,099 gross (534 net) wells across our properties, with an average working interest of 25%, and a 68% value-weighted average working interest, which is calculated by dividing (a) the aggregate sum of the products of each property’s working interest and standardized measure as of June 30, 2010 by (b) the aggregate standardized measure for all properties, as of June 30, 2010. Based on our June 30, 2010 reserve report, the average estimated decline rate for our existing proved developed producing reserves is approximately 10% for 2011, approximately 9% compounded average decline for the subsequent five years and approximately 8% thereafter. As of June 30, 2010, approximately 9.4 MMBoe, or 32%, of our estimated proved reserves were classified as proved undeveloped. Such proved undeveloped reserves were approximately 82% oil and included 315 identified low-risk infill drilling, recompletion and development opportunities in known productive areas. Based on the production estimates from our reserve report dated June 30, 2010, we believe that through 2015, our low-risk development inventory will provide us with the opportunity to grow our average net production to approximately 5,600 Boe/d, without acquiring incremental reserves.


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The following table summarizes pro forma information by producing region regarding our estimated oil and natural gas reserves as of June 30, 2010 and our average net production for the nine months ended September 30, 2010.
 
                                                                         
                                  Average Net
             
    Estimated Pro Forma
          Standardized
    Pro Forma
             
    Net Proved Reserves (MBoe)(1)     % Oil and
    Measure(2)
    Production     Producing Wells  
    Developed     Undeveloped     Total     NGLs     (in millions)     Boe/d     %     Gross     Net  
 
Permian Basin
    9,620       8,179       17,799       90 %   $ 308.4       2,342       45 %     1,661       313  
Ark-La-Tex
    6,761       1,161       7,922       31 %     86.8       1,742       34 %     225       125  
Mid-Continent
    2,155             2,155       47 %     27.3       578       11 %     199       92  
Gulf Coast(3)
    1,735       42       1,777       59 %     44.8       522       10 %     14       4  
                                                                         
Total
    20,271       9,382       29,653       69 %   $ 467.3       5,184       100 %     2,099       534  
                                                                         
 
 
 
(1) Please see page 149 of “Business and Properties — Properties” for a table detailing the degree of depletion of proved reserves for our properties in each of our producing regions and the properties retained by the Fund in each of their producing regions. The degree of depletion of proved reserves with respect to each region was calculated by dividing the proved reserves for such region as of June 30, 2010 by the sum of proved reserves for such region as of June 30, 2010 and the cumulative production from that region.
 
(2) Standardized measure is calculated in accordance with SFAS No. 69, Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities — Oil and Gas. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure.
 
(3) Includes estimated oil reserves attributable to an 8.05% overriding royalty interest on oil production from the Fund’s 92% working interest in the Jay Field, which represents approximately 3% of our pro forma average net daily production for the nine months ended September 30, 2010. For more information regarding our overriding oil royalty interest in the Jay Field, please read “Business and Properties — Summary of Oil and Natural Gas Properties and Projects — Properties — The Gulf Coast Area — Overriding Oil Royalty Interest in Jay Field” on page 154.
 
Our Hedging Strategy
 
We expect to adopt a hedging policy to reduce the impact to our cash flows from commodity price volatility under which we intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated oil and natural gas production over a three-to-five year period at a given point in time. As opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative contracts in connection with material increases in our estimated reserves and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. For the years ending December 31, 2011, 2012, 2013, 2014 and 2015, the Fund will contribute to us at the closing of this offering commodity derivative contracts covering approximately 80%, 71%, 68%, 65% and 47%, respectively, of our estimated oil and natural gas production as of June 30, 2010, based on our reserve report. By removing a significant portion of price volatility associated with our estimated future 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. We intend to enter into future commodity derivative contracts periodically as existing contracts expire, forecasted production levels increase or commodity derivative contract pricing becomes favorable. For a description of our commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts” on page 124.


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Our Business Strategies
 
Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and, over time, to increase our quarterly cash distributions. To achieve our objective, we intend to execute the following business strategies:
 
  •  Pursue accretive acquisitions of long-lived, low-risk producing oil and natural gas properties throughout North America;
 
  •  Strategically utilize our relationship with the Fund to gain access to and, from time to time, acquire its producing oil and natural gas properties that meet our acquisition criteria;
 
  •  Leverage our relationship with the Fund and Quantum Energy Partners to participate in acquisitions of third-party legacy assets and to increase the size and scope of our potential third-party acquisition targets;
 
  •  Reduce costs and maximize recovery to drive value creation in our producing properties;
 
  •  Mitigate commodity price risk and maximize cash flow visibility through a disciplined commodity hedging policy; and
 
  •  Maintain a balanced capital structure to provide financial flexibility for acquisitions.
 
For a more detailed description of our business strategies, please read “Business and Properties — Our Business Strategies” on page 143.
 
Our Competitive Strengths
 
We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:
 
  •  Our diversified asset portfolio is characterized by relatively low geologic risk, well-established production histories and low production decline rates;
 
  •  Our relationship with the Fund, which provides us with access to a portfolio of additional mature producing oil and natural gas properties that meet our acquisition criteria;
 
  •  Our relationship with Quantum Resources Management, which provides us with extensive technical expertise in and familiarity with our core focus areas;
 
  •  Our relationship with Quantum Energy Partners, which will help us in the evaluation and execution of future acquisitions;
 
  •  Our substantial operational control of our assets, which will allow us to manage our operating costs and better control capital expenditures, as well as the timing of development activities;
 
  •  Our management team’s extensive experience in the acquisition, development and integration of oil and natural gas assets;
 
  •  Our significant inventory of identified low-risk, oil-weighted development projects in our core operating regions, which we believe will provide us with the ability to grow our production through 2015, based on production estimates in our reserve report dated June 30, 2010; and
 
  •  Our competitive cost of capital and financial flexibility.
 
For a more detailed discussion of our competitive strengths, please read “Business and Properties — Our Competitive Strengths” on page 144.
 
Our Principal Business Relationships
 
The Fund will be our largest unitholder following the consummation of this offering. We intend to leverage our relationships with the Fund and Quantum Energy Partners to increase our opportunities to


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acquire additional oil and natural gas properties from the Fund in future periods, and to maximize our opportunities to participate in suitable acquisitions from third parties that otherwise may not be available to us. Additionally, these relationships will provide us access to Quantum Resources Management’s and Quantum Energy Partners’ experienced management teams, which we believe will enhance our ability to achieve our primary business objective.
 
Our Relationship with the Fund
 
The Fund is a collection of limited partnerships formed by the founders of Quantum Energy Partners and Don Wolf, the Chairman of the Board of our general partner, for the purpose of acquiring mature, legacy producing oil and natural gas properties with long-lived production profiles. The Fund currently has more than $1.2 billion in assets under management. The Fund is managed by Quantum Resources Management, a full service management company formed to manage the oil and natural gas interests of the Fund. Contemporaneous with the closing of this offering, our general partner will enter into a services agreement with Quantum Resources Management, pursuant to which Quantum Resources Management will agree to provide the administrative and acquisition advisory services that we believe are necessary to allow our general partner to manage, operate and grow our business.
 
After giving effect to its contribution of the Partnership Properties to us, the Fund will retain total estimated proved reserves of 56.4 MMBoe, of which approximately 76% are proved developed reserves, with standardized measure of $630.5 million as of June 30, 2010, and interests in over 1,000 gross (630 net) oil and natural gas wells, with pro forma average net production of approximately 13,132 Boe/d for the nine months ended September 30, 2010. The estimates of proved reserves retained by the Fund, as of June 30, 2010, are based on a report prepared by Miller and Lents, Ltd., the Fund’s independent reserve engineers. The Fund’s retained assets will include legacy properties with characteristics similar to the Partnership Properties, and we believe that the majority of these assets are currently suitable for acquisition by us, based on our criteria that properties consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, low-decline, predictable production profiles. The Fund has informed us that it intends to offer us the opportunity to purchase its additional mature onshore producing oil and natural gas assets, from time to time, in future periods at mutually agreeable prices. For a summary of the process by which such mutually agreeable prices will be determined, please see “Certain Relationships and Related Party Transactions — Review, Approval or Ratification of Transactions with Related Persons” beginning on page 192.
 
The Fund will be contractually committed to providing us with opportunities to purchase additional proved reserves in future periods under specified circumstances. Under the terms of our omnibus agreement, the Fund will commit to offer us the first opportunity to purchase properties that it may offer for sale, so long as the properties consist of at least 70% proved developed producing reserves, as measured by value. Approximately 74% of the estimated reserves to be retained by the Fund are classified as proved developed producing, based on the Fund’s June 30, 2010 third-party reserve report. Additionally, we believe the percentage of the Fund’s estimated reserves classified as proved developed producing will increase over time as the Fund invests its capital to convert its undeveloped properties to proved developed producing. It is difficult to predict which properties the Fund may offer for sale in future periods or the reserve classifications of any such properties. As a result, we are unable to quantify the number of potential sale transactions that may meet the 70% proved developed producing reserve criteria.
 
The Fund will determine whether any group of properties offered for sale meets the 70% threshold, and therefore, whether it is obligated to offer such properties to us. The 70% threshold is a value-weighted determination made by the Fund, acting in good faith pursuant to the terms of our omnibus agreement, and is subject to a number of subjective assumptions. As such, other than the Fund’s obligation to act in good faith, there are no additional safeguards in place to prevent the Fund from selecting a subset of assets that do not meet this standard or allocating value in a manner where the proved developed producing assets are below the 70% threshold. Given the Fund’s significant ownership in us following completion of the offering, we believe there is a sufficient economic incentive to deter


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the Fund from structuring its asset dispositions in an attempt to circumvent our contractual rights under the omnibus agreement.
 
Additionally, the Fund will agree to allow us to participate in its acquisition opportunities to the extent that it invests any of the remaining $170 million of its unfunded committed equity capital. Specifically, the Fund will agree to offer us the first option to acquire at least 25% of each acquisition available to it, so long as at least 70% of the allocated value, as determined by the Fund acting in good faith under the omnibus agreement, is attributable to proved developed producing reserves. In addition to opportunities to purchase proved reserves from, and to participate in future acquisition opportunities with, the Fund, the general partner of the Fund will agree that, if it or its affiliates establish another fund similar to the Fund to acquire oil and natural gas properties within two years of the closing of this offering, it will cause such fund to provide us with a similar right to participate in such fund’s acquisition opportunities. These contractual obligations will remain in effect for five years following the consummation of this offering. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement” on page 188.
 
We believe that, as a holder of an aggregate of approximately 47.5% of our common units and all of our subordinated units upon the consummation of this offering, the Fund will have a vested interest in our ability to increase our reserves and production. Except as provided in the omnibus agreement, as described above, the Fund has no obligation to offer additional properties to us following the consummation of this offering. If the Fund fails to present us with, or successfully competes against us for, acquisition opportunities, then we may not be able to replace or increase our estimated proved reserves, which would adversely affect our cash flow from operations and our ability to make cash distributions to our unitholders.
 
Our Relationship with Quantum Energy Partners
 
Quantum Energy Partners is a private equity firm founded in 1998 to make investments in the energy sector. Quantum Energy Partners currently has more than $5.7 billion in assets under management, including the assets of and remaining capital commitments to the Fund. Two of the co-founders and certain other employees of Quantum Energy Partners own interests in the general partner of the Fund as well as interests in our general partner. The employees of Quantum Energy Partners are experienced energy professionals with expertise in finance and operations and broad technical skills in the oil and natural gas business. In connection with the business of Quantum Energy Partners, these employees review a large number of potential acquisitions and are involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which Quantum Energy Partners owns interests. Although there is no obligation to do so, to the extent not inconsistent with their fiduciary duties and obligations to the investors and other parties involved with Quantum Energy Partners, Quantum Energy Partners may refer to us or allow us to participate in new acquisitions by its portfolio companies and may cause its portfolio companies to contribute or sell oil and natural gas assets to us in transactions that would be beneficial to all parties. Given this potential alignment of interests and the overlapping ownership of the management and general partners of Quantum Energy Partners, the Fund and us, we believe we will benefit from the collective expertise of the employees of Quantum Energy Partners, their extensive network of industry relationships and the access to potential acquisition opportunities that would not otherwise be available to us.
 
Risk Factors
 
An investment in our common units involves risks. Below is a summary of certain key risk factors that you should consider in evaluating an investment in our common units. This list is not exhaustive. Please read the full discussion of these risks and other risks described under “Risk Factors” beginning on page 29.


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Risks Related to Our Business
 
  •  We may not have sufficient cash to pay the minimum quarterly distribution on our common units, following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
  •  We would not have generated sufficient available cash on a pro forma basis to have paid the minimum quarterly distribution on all of our units for the year ended December 31, 2009 or the twelve months ended September 30, 2010.
 
  •  Our estimated oil and natural gas reserves will naturally decline over time, and it is unlikely that we will be able to sustain distributions at the level of our minimum quarterly distribution without making accretive acquisitions or substantial capital expenditures that maintain our asset base.
 
  •  Oil and natural gas prices are very volatile. A decline in oil or natural gas prices will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.
 
Risks Inherent in an Investment in Us
 
  •  Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.
 
  •  Other than certain obligations of the Fund and its general partner with respect to our omnibus agreement, the Fund, Quantum Energy Partners and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses.
 
  •  Neither we nor our general partner have any employees and we rely solely on the employees of Quantum Resources Management to manage our business. Quantum Resources Management will also provide substantially similar services to the Fund, and thus will not be solely focused on our business.
 
  •  The management incentive fee we will pay to our general partner may increase in situations where there is no corresponding increase in distributions to our common unitholders.
 
  •  If our general partner converts a portion of its management incentive fee in respect of a quarter into Class B units, it will be entitled to receive pro rata distributions on those Class B units when and if we pay distributions on our common units, even if the value of our properties declines and a lower management incentive fee is owed in future quarters.
 
  •  Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Affiliates of the Fund and Quantum Energy Partners, as the owners of our general partner, will have the power to appoint and remove our general partner’s directors.
 
  •  Our unitholders will experience immediate and substantial dilution of $15.56 per unit.
 
Tax Risks to Unitholders
 
  •  Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.
 
  •  Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.


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Formation Transactions and Partnership Structure
 
We are a Delaware limited partnership formed by affiliates of the Fund to own and acquire producing oil and natural gas properties. At the closing of this offering, the following transactions, which we refer to as the formation transactions, will occur:
 
  •  The Fund will contribute to us (i) specified oil and natural gas properties and an overriding oil royalty interest, which we refer to collectively as the “Partnership Properties,” and (ii) commodity derivative contracts covering approximately 47% to 80% of our estimated future oil and natural gas production through 2015, based on production estimates in our reserve report dated June 30, 2010;
 
  •  We will issue to the Fund 13,547,737 common units and 7,145,866 subordinated units, representing an aggregate 57.9% limited partner interest in us;
 
  •  We will issue to QRE GP, LLC 35,729 general partner units, representing a 0.1% general partner interest in us, and provide for our general partner’s management incentive fee in our partnership agreement;
 
  •  We expect to receive net proceeds of approximately $275.0 million from the issuance and sale of 15,000,000 common units to the public, representing a 42.0% limited partner interest in us, and we will use the net proceeds as described in “Use of Proceeds” on page 66;
 
  •  We expect to borrow approximately $225 million under a new $750 million revolving credit facility, and we will use the proceeds as described in “Use of Proceeds” on page 66;
 
  •  We will assume approximately $200 million of the Fund’s debt that currently burdens the Partnership Properties. We will use $200 million of the borrowings under our credit facility to repay in full such assumed debt at the closing of this offering. Please read “Use of Proceeds” on page 66;
 
  •  Our general partner will enter into a services agreement with Quantum Resources Management, pursuant to which Quantum Resources Management will agree to provide our general partner with the services that we believe are necessary to manage, operate and grow our business; and
 
  •  We will enter into an omnibus agreement with affiliates of the Fund that will address certain competition and indemnification matters, as well as our right to purchase certain properties that the Fund may offer for sale in future periods and our right to acquire 25% of certain acquisitions available to the Fund in future periods.
 
To the extent the underwriters exercise their option to purchase up to an additional 2,250,000 common units, the number of common units issued to the Fund (as reflected in the second bullet above) will decrease by, and the number of common units issued to the public (as reflected by the fourth bullet above) will increase by, the aggregate number of common units purchased by the underwriters pursuant to such exercise. The proceeds from any exercise of the underwriters’ option to purchase additional common units will be paid to the Fund.


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Ownership and Organizational Structure of QR Energy, LP
 
The diagram below illustrates our ownership and organizational structure based on total units outstanding after giving effect to this offering and the related formation transactions and assumes that the underwriters do not exercise their option to purchase additional common units.
 
         
    Ownership
 
    Interest  
 
Common Units held by the public
    42.0 %
Common Units held by the Fund
    37.9 %
Subordinated Units held by the Fund
    20.0 %
General Partner Units
    0.1 %
         
Total
    100 %
         
 
(FLOW CHART)
 
 
(1) Our general partner, QRE GP, LLC, will be owned 50% by an entity controlled by Toby R. Neugebauer and S. Wil VanLoh, Jr., who are directors of our general partner and also Managing Partners of Quantum Energy Partners, and 50% by an entity controlled by Alan Smith, the Chief Executive Officer and a director of our general partner and the Chief Executive Officer and a director of Quantum Resources Management, and John Campbell, the President and Chief Operating Officer and a director of our general partner and the President, Chief Operating Officer and a director of Quantum Resources Management.
 
(2) An entity controlled by Messrs. Neugebauer and VanLoh owns a majority interest in the entities that control each of the limited partnerships and other entities comprising the Fund, and Messrs. Neugebauer, VanLoh, Smith and Campbell and Donald D. Wolf, the Chairman of the Board of our general partner, acting collectively, control such entities.


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Management of QR Energy, LP
 
Our general partner has sole responsibility for conducting our business and managing our operations. Our general partner’s board of directors and executive officers will make decisions on our behalf. Contemporaneous with the closing of this offering, our general partner will enter into a services agreement with Quantum Resources Management, pursuant to which Quantum Resources Management will agree to provide the administrative and acquisition advisory services that we believe are necessary to allow our general partner to operate, manage and grow our business. Neither we nor our general partner have any employees. Quantum Resources Management employs or will employ, all of our general partner’s officers and the employees who operate our business, and certain of these officers and employees also provide similar services to the Fund. Certain officers and directors of our general partner are also officers or directors of Quantum Resources Management or its affiliates. The administrative services and management incentive fees described below, and the respective agreements that provide for such fees, have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. For a detailed description of our management, please read “Management — Management of QR Energy, LP” on page 170.
 
Administrative Services Fee
 
Under the services agreement, from the closing of this offering through December 31, 2012, Quantum Resources Management will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. It is anticipated that this amount will not reflect the actual costs of such services, and accordingly the Fund will be subsidizing our operations for any shortfall through December 31, 2012. For the nine months ended September 30, 2010, 3.5% of our unaudited pro forma Adjusted EBITDA, calculated prior to the payment of the fee, would have been approximately $2.0 million. For the twelve months ending December 31, 2011, 3.5% of such estimated Adjusted EBITDA, calculated prior to the payment of the fee, would be approximately $3.1 million, assuming we generate estimated Adjusted EBITDA as set forth in “Cash Distribution Policy and Restrictions on Distributions — Estimated Adjusted EBITDA for the Twelve Months Ending December 31, 2011” beginning on page 77. After December 31, 2012, in lieu of the quarterly administrative services fee, our general partner will reimburse Quantum Resources Management, on a quarterly basis, for the actual direct and indirect expenses it incurs in its performance under the services agreement, and we will reimburse our general partner for such payments it makes to Quantum Resources Management. Quantum Resources Management will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. For a detailed description of the administrative services fee, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement’’ on page 188.
 
Management Incentive Fee
 
Under our partnership agreement, for each quarter for which we have paid cash distributions that equaled or exceeded 115% of our minimum quarterly distribution (which amount we refer to as our “Target Distribution”), or $0.4744 per unit, our general partner will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of our management incentive fee base, which will be an amount equal to the sum of:
 
  •  the future net revenue of our estimated proved oil and natural gas reserves, discounted to present value at 10% per annum based on SEC methodology, which is calculated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable twelve-month period, adjusted for our commodity derivative contracts; and
 
  •  the fair market value of our assets, other than our estimated oil and natural gas reserves and our commodity derivative contracts, that principally produce qualifying income for federal income tax


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  purposes, at such value as may be determined by the board of directors of our general partner and approved by the conflicts committee of our general partner’s board of directors.
 
We refer to this fee as the “management incentive fee.” The management incentive fee base will be calculated as of December 31 (with respect to the first and second calendar quarters and based on a third-party fully engineered reserve report) or June 30 (with respect to the third and fourth calendar quarters and based on an internally engineered reserve report, unless estimated proved reserves increased by more than 20% since the previous calculation date, in which case a third-party audit of our internal estimates will be performed) immediately preceding the quarter in respect of which payment of a management incentive fee is due. Applying this formula to our estimated pro forma proved reserves as of June 30, 2010, adjusted for our commodity derivative contracts, and assuming quarterly distributions equal to or exceeding our Target Distribution, our general partner would have been entitled to a management incentive fee of approximately $1.3 million in respect of the quarter ending September 30, 2010 (or $5.3 million on an annualized basis).
 
As indirect owners of our general partner, Messrs. Neugebauer, VanLoh, Smith and Campbell will receive a portion of our general partner’s management incentive fee during any quarter in which our general partner is entitled to receive the management incentive fee. Additionally, both owners of our general partner have agreed to pay each of Cedric W. Burgher, our Chief Financial Officer, and Don Wolf, the Chairman of the board of directors of our general partner, up to 0.75% of each owner’s share of any management incentive fee paid to our general partner during the period of their respective service to our general partner. The portion of any quarterly management incentive fee paid to Messrs. Burgher and Wolf will not be an expense reimbursed by our general partner or us under our general partner’s administrative services agreement with Quantum Resources Management.
 
For a detailed description of the management incentive fee, please read “Provisions of our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — General Partner Interest and Management Incentive Fee” on page 100 and “— General Partner’s Right to Convert Management Incentive Fee into Class B Units” on page 101.
 
Conversion and Reset of Management Incentive Fee
 
From and after the end of the subordination period, and subject to certain limitations, our general partner will have the continuing right, from time to time, to convert up to 80% of its management incentive fee into Class B units, which have the same rights, preferences and privileges as our common units, except in liquidation, and will be convertible into common units at the holder’s election, thereby increasing our general partner’s ownership and economic interest in us. If our general partner exercises its right to convert a portion of the management incentive fee with respect to that quarter into Class B units, then the management incentive fee base described above will be reduced in proportion to the percentage of such fee converted. As a result, any conversion will reduce the amount of the management incentive fee for subsequent quarters, subject to potential increases in future quarters as a result of an increase in our management incentive fee base. Our general partner will, however, be entitled to receive distributions on the Class B units that it owns as a result of converting the management incentive fee, including in respect of the quarter for which such fee was converted. The reduction in the management incentive fee as a result of any conversion will directly offset the increase in distributions required by the newly issued Class B units. In addition, following a conversion, our general partner will be able to make subsequent conversions once certain conditions have been met.
 
As indirect owners of our general partner, Messrs. Neugebauer, VanLoh, Smith and Campbell will receive a portion of any cash distributions made in respect of any converted Class B units held by our general partner. Additionally, each of Mr. Burgher and Mr. Wolf will be entitled to receive his proportionate share of any Class B units (including any quarterly cash distributions made in respect of such Class B units) into which his share of the management incentive fee is converted. For a detailed description of the management incentive fee, please read “Provisions of our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — General Partner Interest and


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Management Incentive Fee” on page 100 and “— General Partner’s Right to Convert Management Incentive Fee into Class B Units” on page 101.
 
Principal Executive Offices and Internet Address
 
Our principal executive offices are located at 5 Houston Center, 1401 McKinney Street, Suite 2400, Houston, Texas 77010, and our phone number is (713) 452-2200. Our website address is www.qrenergylp.com and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.
 
Summary of Conflicts of Interest and Fiduciary Duties
 
Our general partner has a legal duty to manage us in a manner beneficial to the holders of our common and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, the officers and directors of our general partner also have a fiduciary duty to manage the business of our general partner in a manner beneficial to its owners, each of which is an affiliate of the Fund and Quantum Energy Partners. Both the Fund and Quantum Energy Partners and their respective affiliates manage, own and hold investments in other funds and companies that compete with us. Additionally, certain of our executive officers and directors will continue to have economic interests, investments and other economic incentives in funds affiliated with Quantum Energy Partners. As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its owners and affiliates, on the other hand. For example, our general partner is entitled to make determinations that affect our ability to generate the cash flows necessary to make cash distributions to our unitholders, including determinations related to:
 
  •  purchases and sales of oil and natural gas properties and other acquisitions and dispositions, including whether to pursue acquisitions that are also suitable for the Fund, Quantum Energy Partners or their affiliates;
 
  •  the manner in which our business is operated;
 
  •  the level of our borrowings;
 
  •  the amount, nature and timing of our capital expenditures; and
 
  •  the amount of cash reserves necessary or appropriate to satisfy our general, administrative and other expenses and debt service requirements and to otherwise provide for the proper conduct of our business.
 
For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Risk Factors — Risks Inherent in an Investment in Us” beginning on page 48 and “Conflicts of Interest and Fiduciary Duties” beginning on page 193.
 
Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by the Fund and its affiliates) after the subordination period has ended. Upon consummation of this offering, affiliates of the Fund and Quantum Energy Partners will own our general partner and, through ownership of the general partner of the Fund, will control the voting of an aggregate of approximately 47.5% of our outstanding common units and all of our subordinated units, and, assuming we do not issue any additional common units and the Fund does not transfer its common units, the Fund will have the ability to amend our partnership agreement,


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including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholder once the subordination period ends. Please see “Risk Factors — Risks Inherent in an Investment in Us” beginning on page 48 and “The Partnership Agreement — Amendment of the Partnership Agreement” beginning on page 210.
 
Partnership Agreement Modification of Fiduciary Duties
 
Our partnership agreement limits the liability of our general partner and reduces the fiduciary duties it owes to holders of our common units. Our partnership agreement also restricts the remedies available to holders of our common units for actions that might otherwise constitute a breach of the fiduciary duties that our general partner owes to our unitholders. By purchasing a common unit, unitholders agree to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, are treated as having consented to various actions contemplated in our partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” beginning on page 201 for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to our unitholders.
 
The Fund, Quantum Energy Partners and their Respective Affiliates Compete with Us
 
Our partnership agreement contains no restrictions on the ability of the Fund, Quantum Energy Partners and their respective affiliates, including their portfolio investments, to compete with us. Other than the obligations of the Fund and its general partner under the omnibus agreement, neither the Fund or Quantum Energy Partners, nor any of their respective affiliates, is under any obligation to offer properties or refer acquisitions to us. For a detailed discussion of the terms of the omnibus agreement, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement” on page 188.
 
Conflicts of Interest of our General Partner’s Directors and Officers
 
To maintain and increase our estimated proved reserves and levels of production, we intend to acquire additional oil and natural gas properties and, to a lesser extent, deploy our capital resources to drill additional wells and otherwise develop our estimated proved undeveloped reserves. Several of the officers and directors of our general partner, who are responsible for managing our operations and acquisition activities, hold similar positions with other entities that are in the business of identifying and acquiring oil and natural gas properties. For example, our general partner will be owned 50% by an entity controlled by Mr. Neugebauer and Mr. VanLoh, who are directors of our general partner and also managing partners of Quantum Energy Partners, and 50% by an entity controlled by Mr. Smith, our Chief Executive Officer, a director of our general partner and Chief Executive Officer and a director of Quantum Resources Management, and Mr. Campbell, our President and Chief Operating Officer, a director of our general partner and President, Chief Operating Officer and a director of Quantum Resources Management. Additionally, Quantum Energy Partners is in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties. Mr. Neugebauer and Mr. VanLoh are also directors of several other oil and natural gas companies that are in the business of acquiring oil and natural gas properties. Messrs. Smith and Campbell, who held positions as Managing Directors of Quantum Energy Partners prior to assuming their current positions with Quantum Resources Management, continue to hold ownership interests in certain of the funds constituting Quantum Energy Partners, continue to serve on the investment committee that oversees material investment decisions made by Quantum Energy Partners and serve on the boards of or consult with various of the portfolio companies in which Quantum Energy Partners holds interests. It is not expected that the time that Messrs. Smith and Campbell devote to Quantum Energy Partners matters will materially interfere with their primary involvement and duties to Quantum Resources Management and us.


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Mr. Burgher, our Chief Financial Officer, serves on the board of a Quantum Energy Partners portfolio company and will also serve as interim Chief Financial Officer for the Fund until a permanent replacement is hired. Additionally, Mr. Burgher will continue to hold an ownership interest in, and will have economic incentives related to, one of the funds constituting Quantum Energy Partners.
 
After the closing of this offering, officers of our general partner will continue to devote significant time to the other businesses, including businesses to which Quantum Resources Management provides management and administrative services. We cannot assure you that any conflicts that may arise between us and our unitholders, on the one hand, and the Fund or Quantum Resources Management, on the other hand, will be resolved in our favor.
 
The existing positions held by these directors and officers may give rise to fiduciary duties that are in conflict with the fiduciary duties they owe to us. These officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present them to us. For a complete discussion of our management’s business affiliations and the potential conflicts of interest of which unitholders should be aware, please read “Business and Properties — Our Principal Business Relationships” beginning on page 146, “Certain Relationships and Related Party Transactions — Limited Liability Company Agreement of Our General Partner” beginning on page 187 and “Conflicts of Interest and Fiduciary Duties” beginning on page 193.
 
Role of our Conflicts Committee in Acquisitions from and Joint Opportunities with the Fund and Quantum Energy Partners
 
A fundamental component of our business strategy is to pursue opportunities to acquire assets from the Fund and Quantum Energy Partners. Inherent conflicts of interest will exist between us and our unitholders, on the one hand, and our general partner and its affiliates (including the Fund and Quantum Energy Partners), on the other hand, in determining the appropriate purchase price and terms relating to our future acquisition of oil and natural gas properties from the Fund or any affiliate of Quantum Energy Partners.
 
The board of directors of our general partner will be comprised of six directors, including one independent director, at the completion of this offering, will have a standing conflicts committee comprised of at least one independent director and, pursuant to the regulations of the NYSE, will add a second independent director within 90 days of the closing of this offering and a third independent director within one year of the closing of this offering, each of whom we expect to also serve on the conflicts committee. The board of directors of our general partner will determine whether to seek the approval of the conflicts committee in connection with each future acquisition of oil and natural gas properties from the Fund or any affiliate of Quantum Energy Partners. In addition to acquisitions from the Fund or any affiliate of Quantum Energy Partners, the board of directors of our general partner will also determine whether to seek conflicts committee approval to the extent we act jointly with the Fund, Quantum Energy Partners or their respective affiliates to acquire additional oil and natural gas properties. Pursuant to the terms of our partnership agreement, our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with our general partner or affiliates, including in connection with these types of transactions. If the board of directors of our general partner elects to seek conflicts committee approval in connection with future acquisitions, then under our partnership agreement, the conflicts committee will be entitled to hire its own financial and legal advisors in connection with any matters on which the board of directors of our general partner seeks the conflicts committee’s approval. For more detailed information regarding our conflicts committee, please read “Form of Amended and Restated Agreement of Limited Partnership of QR Energy, LP” included in this prospectus as Appendix A.


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The Offering
 
Common units offered by us 15,000,000 common units, or 17,250,000 common units if the underwriters exercise in full their option to purchase additional common units.
 
Units outstanding after this offering 28,547,737 common units and 7,145,866 subordinated units, representing 79.9% and 20%, respectively, limited partner interests in us. If the underwriters do not exercise their option to purchase additional common units, we will issue common units to the Fund at the expiration of the option period. To the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder of the common units subject to the option, if any, will be issued to the Fund at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. In addition, our general partner will own general partner units representing a 0.1% general partner interest in us.
 
Use of proceeds We expect to receive net proceeds from the issuance and sale of the 15,000,000 common units offered hereby of approximately $275.0 million, after deducting underwriting discounts, structuring fees and expenses. We intend to use all of the net proceeds from this offering, together with borrowings of approximately $225 million under our new revolving credit facility, to make a cash distribution to the Fund of approximately $300.0 million and to repay in full $200 million of the Fund’s debt that we will assume at closing. The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be paid to the Fund. Please read “Use of Proceeds” on page 66.
 
Cash distributions We expect to make a minimum quarterly distribution of $0.4125 per unit per quarter on all common, subordinated, Class B, if any, and general partner units ($1.65 per unit on an annualized basis) to the extent we have sufficient cash from operations, after the establishment of cash reserves and the payment of fees and expenses, including payments to our general partner for reimbursement of expenses under the services agreement and payment of the management incentive fee to the extent due. We refer to this cash as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A and in the glossary included in this prospectus as Appendix B.
 
Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail in “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 70.


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We expect to pay our unitholders a prorated cash distribution for the first quarter ending after the closing of this offering. The prorated distribution will cover the period from the first day following the closing of this offering to and including December 31, 2010. While the fourth quarter is not complete, based on our internal preliminary results of operations, we estimate that available cash generated during the three months ending December 31, 2010 would not have been sufficient to make a cash distribution at the minimum quarterly distribution of $0.4125 per unit on all of the common units, subordinated units, and general partner units if such units had been outstanding during the entire fourth quarter of 2010.
 
Assuming our general partner maintains its 0.1% general partner interest in us, our partnership agreement requires us to distribute all of our available cash, calculated as of the end of each quarter, in the following manner during the subordination period:
 
• First, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
 
• Second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;
 
• Third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
 
• Thereafter, 99.9% to the common and subordinated unitholders, pro rata, and 0.1% to our general partner.
 
If cash distributions equal or exceed the Target Distribution of $0.4744 per common unit (which is an amount equal to 115% of the minimum quarterly distribution) for any calendar quarter, then, subject to certain limitations, our general partner will receive (in addition to distributions on its general partner units) a quarterly management incentive fee, as described in “— Management Incentive Fee” on page 18. Payment of the management incentive fee will reduce cash available for distribution to our unitholders.
 
If we had completed the formation transactions contemplated in this prospectus and the acquisition of all of the Partnership Properties on January 1, 2009, our unaudited pro forma available cash for the year ended December 31, 2009 would have been approximately $47.7 million. This amount would not have been sufficient to make a cash distribution for the year ended December 31, 2009 at the minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on


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an annualized basis) on all of the common units, subordinated units, and general partner units. Specifically, this amount would have been sufficient to allow us to pay the full minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units, but only a cash distribution of $0.0190 per unit per quarter (or $0.08 per unit on an annualized basis) on all of the subordinated units, or approximately 4.6% of the minimum quarterly distribution.
 
If we had completed the transactions contemplated in this prospectus and the acquisition of the Partnership Properties on October 1, 2009, our pro forma available cash for the twelve months ended September 30, 2010 would have been approximately $51.3 million. This amount would not have been sufficient to make a cash distribution for the twelve months ended September 30, 2010 at the minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units, subordinated units, and general partner units. Specifically, this amount would have been sufficient to allow us to pay the full minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units, but only a cash distribution of $0.1447 per unit per quarter (or $0.58 per unit on an annualized basis) on all of the subordinated units, or approximately 35.1% of the minimum quarterly distribution.
 
While the fourth quarter is not complete, based on our internal preliminary results of operations, we estimate that available cash generated during the three months ending December 31, 2010 would not have been sufficient to make a cash distribution at the minimum quarterly distribution of $0.4125 per unit on all of the common units, subordinated units, and general partner units if such units had been outstanding during the entire fourth quarter of 2010.
 
For a calculation of our ability to have made distributions to unitholders based on our pro forma results of operations for the year ended December 31, 2009 and the twelve months ended September 30, 2010, please read “Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Available Cash for the Year Ended December 31, 2009 and the Twelve Months Ended September 30, 2010” on page 74.
 
We believe that we will have sufficient cash flow from operations to make cash distributions for each quarter for the twelve months ending December 31, 2011 at the minimum quarterly distribution of $0.4125 per unit on all common, subordinated and general partner units. Please read “Our Cash Distribution Policy and Restrictions on Distributions — “Estimated Adjusted EBITDA for the Twelve Months Ending December 31, 2011’’ on page 77.


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Subordinated units Following the consummation of this offering, the Fund will own all of our subordinated units. The principal difference between our common and subordinated units is that, in any quarter during the subordination period, the subordinated units are entitled to receive the minimum quarterly distribution of $0.4125 per unit ($1.65 per unit on an annualized basis) only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.
 
Subordination period The subordination period will end on the earlier of:
 
• the later to occur of (i) the second anniversary of the closing of this offering and (ii) such date as all arrearages, if any, of distributions of the minimum quarterly distribution on the common units have been eliminated; and
 
• the removal of our general partner other than for cause, provided that no subordinated units or common units held by the holders of the subordinated units or their affiliates are voted in favor of such removal.
 
Management incentive fee Under our partnership agreement, for each quarter for which we have paid cash distributions that equaled or exceeded 115% of the minimum quarterly distribution, which we refer to as the Target Distribution, our general partner will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of our management incentive fee base, which will be an amount equal to the sum of:
 
• the future net revenue of our estimated proved oil and natural gas reserves, discounted to present value at 10% per annum and calculated based on SEC methodology, adjusted for our commodity derivative contracts; and
 
• the fair market value of our assets, other than our estimated oil and natural gas reserves and our commodity derivative contracts, that principally produce qualifying income for federal income tax purposes, at such value as may be determined by the board of directors of our general partner and approved by the conflicts committee of our general partner’s board of directors.
 
The management incentive fee base will be calculated as of the December 31 (with respect to the first and second calendar quarters and based on a third-party fully engineered reserve report) or June 30 (with respect to the third and fourth calendar quarters and based on an internally engineered reserve report, unless estimated proved reserves increased by more than 20% since the previous calculation date, in which case a third-party audit of our internal estimates will be performed) immediately preceding the quarter in respect of which payment of a management incentive fee is due.


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No portion of the management incentive fee determined for any calendar quarter will be earned or payable unless we have paid (or have reserved for payment) a quarterly distribution that equaled or exceeded the Target Distribution for such quarter. In addition, the amount of the management incentive fee otherwise payable with respect to any calendar quarter will be reduced to the extent that giving effect to the payment of such management incentive fee would cause adjusted operating surplus (which is defined in “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — General Partner Interest and Management Incentive Fee’’ on page 100) generated during such quarter to be less than 100% of our quarterly distribution paid (or reserved for payment) for such quarter on all outstanding common, Class B, if any, subordinated and general partner units. Any portion of the management incentive fee not paid as a result of the foregoing limitations will not accrue or be payable in future quarters.
 
Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — General Partner Interest and Management Incentive Fee” on page 100.
 
Conversion of the management incentive fee into Class B units and related reset of the management incentive fee base From and after the end of the subordination period and subject to certain exceptions, our general partner will have the continuing right, at any time when it has received all or any portion of the management incentive fee for three consecutive quarters and shall be entitled to receive all or a portion of the management incentive fee for a fourth consecutive quarter, to convert into Class B units up to 80% of the management incentive fee for the fourth quarter in lieu of receiving a cash payment for such portion of the management incentive fee. The number of Class B units (rounded to the nearest whole number) to be issued in connection with such a conversion will be equal to (a) the product of: (i) the applicable percentage (up to 80%) of the management incentive fee our general partner has elected to convert, and (ii) the average of the management incentive fee paid to our general partner for the quarter immediately preceding the quarter for which such fee is to be converted and the management incentive fee payable to our general partner for the quarter for which such fee is to be converted, divided by (b) the cash distribution per unit for the most recently completed quarter.
 
The Class B units will have the same rights, preferences and privileges of our common units and will be entitled to the same cash distributions per unit as our common units, except in liquidation where distributions are made in accordance with the respective capital accounts of the units, and will be convertible into an equal number of common units at the election of the


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holder. If our general partner exercises its right to convert a portion of the management incentive fee with respect to any quarter into Class B units, then the management incentive fee base described above will be reduced in proportion to the percentage of such fee converted. As a result, any conversion will reduce the amount of the management incentive fee for all subsequent quarters, subject to potential increases in future quarters as a result of an increase in our management incentive fee base. Our general partner will, however, be entitled to receive distributions on the Class B units that it owns as a result of converting the management incentive fee. The reduction in the management incentive fee as a result of any conversion will directly offset the increase in distributions required by the newly issued Class B units. In addition, following a conversion, our general partner will be able to make subsequent conversions once certain conditions have been met. For a detailed description of this conversion right, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — General Partner’s Right to Convert Management Incentive Fee into Class B Units” on page 101.
 
Issuance of additional units We can issue an unlimited number of additional units, including units that are senior to the common units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read “Units Eligible for Future Sale” on page 220 and “The Partnership Agreement — Issuance of Additional Interests” on page 210.
 
Limited voting rights Our general partner will manage us and operate our business. Unlike stockholders of a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, the Fund, its owners and their affiliates will own an aggregate of approximately 47.5% of our common and 100% of our subordinated units and, therefore, will be able to prevent the removal of our general partner. Please read “The Partnership Agreement — Limited Voting Rights” on page 207.
 
Limited call right If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon the consummation of this offering, our general partner, its owners and their affiliates, including the Fund, will own an aggregate of 47.5% of our common and 100% of our subordinated units.


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Please read “The Partnership Agreement — Limited Call Right” on page 216.
 
Eligible Holders and redemption Units held by persons who our general partner determines are not Eligible Holders will be subject to redemption. As used herein, an Eligible Holder means any person or entity qualified to hold an interest in oil and natural gas leases on federal lands. If, following a request by our general partner, a transferee or unitholder, as the case may be, does not properly complete the transfer application or recertification, for any reason, we will have the right to redeem such units at the then-current market price of such units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of the Common Units — Transfer of Common Units” on page 204 and “The Partnership Agreement — Non-Eligible Holders; Redemption” on page 217.
 
Estimated ratio of taxable income to distributions We estimate that if our unitholders own the common units purchased in this offering through the record date for distributions for the period ending December 31, 2013, such unitholders will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 20% of the cash distributed to such unitholders with respect to that period. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” on page 225 for the basis of this estimate.
 
Material tax consequences For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences” beginning on page 222.
 
Listing and trading symbol We have been approved to list our common units on the New York Stock Exchange, subject to official notice of issuance, under the symbol “QRE”.


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Summary Historical and Pro Forma Financial Data
 
The following table shows summary historical financial data of QA Holdings, LP, our predecessor for accounting purposes, which we refer to as our predecessor, and unaudited pro forma condensed financial data of QR Energy, LP for the periods and as of the dates presented. Our predecessor owns the general partner of each of the partnerships comprising the Fund. Our predecessor is deemed to have effective control of all of the partnerships comprising the Fund and, therefore, our predecessor consolidates the results of the partnerships comprising the Fund in its consolidated financial statements. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” on page 112, our future results of operations will not be comparable to the historical results of our predecessor. The summary historical consolidated financial data as of December 31, 2008 and 2009 and for the years ended December 31, 2007, 2008 and 2009 are derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus. The summary historical consolidated financial data presented as of September 30, 2010 and for the nine months ended September 30, 2009 and 2010 are derived from the unaudited historical consolidated financial statements of our predecessor included elsewhere in this prospectus.
 
The summary unaudited pro forma financial data as of September 30, 2010 and for the nine months ended September 30, 2010 and the year ended December 31, 2009 are derived from the unaudited pro forma condensed financial statements of QR Energy, LP included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions, which have been completed or which will be effected prior to or in connection with the closing of this offering, had taken place on September 30, 2010, in the case of the unaudited pro forma balance sheet, or as of January 1, 2009, in the case of the unaudited pro forma statements of operations. These transactions include:
 
  •  adjustments to reflect the acquisition of the Denbury Assets consummated by our predecessor in May 2010;
 
  •  the contribution by the Fund to us of the Partnership Properties in exchange for 13,547,737 common units, 7,145,866 subordinated units and $300.0 million in cash, including approximately $225 million borrowed under our new credit facility, as described below;
 
  •  the issuance to QRE GP, LLC of 35,729 general partner units, representing a 0.1% general partner interest in us, and the provision for our general partner’s management incentive fee in accordance with our partnership agreement;
 
  •  the issuance and sale by us to the public of 15,000,000 common units in this offering and the application of the net proceeds as described in “Use of Proceeds” on page 66;
 
  •  our borrowing of approximately $225 million under our new $750 million revolving credit facility and the application of the proceeds as described in “Use of Proceeds” on page 66; and
 
  •  our assumption of approximately $200 million of the Fund’s debt that currently burdens the Partnership Properties. We will use $200 million of the borrowings under our credit facility to repay in full such assumed debt at the closing of this offering, as described in “Use of Proceeds” on page 66.
 
You should read the following table in conjunction with “— Formation Transactions and Partnership Structure” on page 8, “Use of Proceeds” on page 66, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 112, the historical consolidated financial statements of our predecessor and the unaudited pro forma condensed financial statements of QR Energy, LP included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma consolidated financial statements include more detailed information regarding the basis of presentation for the following information.
 
The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in evaluating the liquidity of our business. This measure is not calculated or presented in accordance with


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generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to the most directly comparable financial measures calculated and presented in accordance with GAAP.
 
                                                         
                                  QR Energy, LP
 
                                  Pro Forma  
    Our Predecessor           Nine Months
 
                      Nine Months Ended
    Year Ended
    Ended
 
    Year Ended December 31,     September 30,     December 31,
    September 30,
 
    2007     2008     2009     2009     2010     2009     2010  
                      (in thousands)              
 
Statement of Operations Data:
                                                       
Revenues:
                                                       
Oil, natural gas, NGL and sulfur sales
  $ 164,628     $ 248,529     $ 69,193     $ 49,071     $ 170,647     $ 76,904     $ 74,308  
Processing fees and other
    6,689       32,541       3,608       4,007       4,823              
                                                         
Total revenues
  $ 171,317     $ 281,070     $ 72,801     $ 53,078     $ 175,470     $ 76,904     $ 74,308  
                                                         
Operating costs and expenses:
                                                       
Lease operating
  $ 77,767     $ 90,424     $ 33,328     $ 23,724     $ 52,152     $ 23,783     $ 15,242  
Production taxes
    12,954       14,566       7,587       4,975       12,528       5,764       3,325  
Transportation and processing
    4,728       26,189       3,926       2,955       3,876       1,534       937  
Impairment of oil and gas properties(1)
          451,440       28,338       28,338             13,912        
Depreciation, depletion and amortization
    42,889       49,309       16,993       13,743       45,149       24,400       18,316  
Accretion of asset retirement obligations
    2,751       3,004       3,585       2,847       2,648       827       822  
Fund management fees(2)
    11,482       12,018       12,018       9,013       7,885              
Acquisition evaluation costs
                      7       1,197              
General and administrative and other
    20,677       14,852       19,461       12,916       19,400       11,268       12,329  
Bargain purchase gain
                (1,200 )     (1,200 )                  
                                                         
Total operating costs and expenses
  $ 173,248     $ 661,802     $ 124,036     $ 97,318     $ 144,835     $ 81,488     $ 50,971  
                                                         
Income (loss) from operations
  $ (1,931 )   $ (380,732 )   $ (51,235 )   $ (44,240 )   $ 30,635     $ (4,584 )   $ 23,337  
                                                         
Other income (expenses):
                                                       
Interest income
  $ 978     $ 617     $ 37     $ 32     $ 27     $     $  
Realized gains (losses) on commodity derivative contracts
    6,861       (34,666 )     47,993       42,177       5,132       23,595       2,093  
Unrealized gains (losses) on commodity derivative contracts
    (157,250 )     169,321       (111,113 )     (74,123 )     41,432       (54,628 )     16,894  
Interest expense
    (17,359 )     (13,034 )     (3,753 )     (2,939 )     (31,392 )     (7,770 )     (5,827 )
Other
    7       (10,039 )     2,657       2,240       5,147              
                                                         
Total other income (expense)
  $ (166,763 )   $ 112,199     $ (64,179 )   $ (32,613 )   $ 20,346     $ (38,803 )   $ 13,160  
                                                         
Net income (loss)
  $ (168,694 )   $ (268,533 )   $ (115,414 )   $ (76,853 )   $ 50,981     $ (43,387 )   $ 36,497  
                                                         
Other Financial Data:
                                                       
Adjusted EBITDA
  $ 50,577     $ 78,316     $ 48,331     $ 45,105     $ 88,711     $ 66,989     $ 54,906  
Cash Flow Data:
                                                       
Net cash provided by (used in):
                                                       
Operating activities
  $ 24,839     $ 75,282     $ 64,907     $ 44,560     $ 50,762                  
Investing activities
    (72,953 )     (137,161 )     (55,458 )     (41,321 )     (931,044 )                
Financing activities
    89,890       30,240       (13,328 )     (5,728 )     884,466                  
 
 
(1) Our predecessor recorded full-cost ceiling test impairments associated with its oil and natural gas properties in both 2008 and 2009. Please read Note 2(i) of the Notes to the Consolidated Financial Statements of our predecessor included elsewhere in this prospectus.
 
(2) Represents fees paid by the Fund to its general partner for the provision of certain administrative and acquisition services.


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                QR Energy, LP
    Our Predecessor   Pro Forma
    As of December 31,   As of September 30,
  As of September 30,
    2008   2009   2010   2010
    (in thousands)
 
Balance Sheet Data:
                               
Working capital
  $ 67,139     $ (74 )   $ 23,971     $ 12,221  
Total assets
    304,937       226,770       1,245,793       404,628  
Total debt
    88,750       86,450       547,668       225,000  
Non-controlling interests
    133,978       14,733       482,552        
Partners’ capital
    5,957       (1,421 )     16,795       158,502  


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Non-GAAP Financial Measures
 
We include in this prospectus the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash from operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income:
 
  •  Plus:
 
  •  Interest expense, including realized and unrealized gains and losses on interest rate derivative contracts;
 
  •  Depletion, depreciation and amortization;
 
  •  Accretion of asset retirement obligations;
 
  •  Unrealized losses on commodity derivative contracts;
 
  •  Impairments; and
 
  •  General and administrative expenses that are allocated to us in accordance with GAAP in excess of the administrative services fee paid by our general partner and reimbursed by us.
 
  •  Less:
 
  •  Interest income; and
 
  •  Unrealized gains on commodity derivative contracts.
 
We use Adjusted EBITDA to calculate the quarterly administrative services fee our general partner pays to Quantum Resources Management under the services agreement between our general partner and Quantum Resources Management. Please read “Business and Properties — Operations — Administrative Services Fee” on page 161 and “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement” on page 188.
 
Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:
 
  •  the cash flow generated by our assets, without regard to financing methods, capital structure or historical cost basis; and
 
  •  the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness.
 
In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.
 
Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA. The table below further presents a


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reconciliation of Adjusted EBITDA to cash flows from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.
 
Calculation of Adjusted EBITDA
 
                                                         
                                  QR Energy, LP
 
    Our Predecessor     Pro Forma  
                      Nine Months Ended
    Year Ended
    Nine Months
 
    Year Ended December 31,     September 30,     December 31,
    Ended September 30,
 
    2007     2008     2009     2009     2010     2009     2010  
    (in thousands)  
 
Net income (loss)
  $ (168,694 )   $ (268,533 )   $ (115,414 )   $ (76,853 )   $ 50,981     $ (43,387 )   $ 36,497  
Unrealized (gains) losses on commodity derivative contracts
    157,250       (169,321 )     111,113       74,123       (41,432 )     54,628       (16,894 )
Depletion, depreciation and amortization
    42,889       49,309       16,993       13,743       45,149       24,400       18,316  
Accretion of asset retirement obligations
    2,751       3,004       3,585       2,847       2,648       827       822  
Interest income
    (978 )     (617 )     (37 )     (32 )     (27 )            
Interest expense
    17,359       13,034       3,753       2,939       31,392       7,770       5,827  
Impairment expense
          451,440       28,338       28,338             13,912        
General and administrative expense in excess of the administrative services fee
                                  8,839       10,338  
                                                         
Adjusted EBITDA
  $ 50,577     $ 78,316     $ 48,331     $ 45,105     $ 88,711     $ 66,989     $ 54,906  
                                                         
 
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA
 
                                         
    Our Predecessor  
          Nine Months Ended
 
    Year Ended December 31,     September 30,  
    2007     2008     2009     2009     2010  
 
Net cash provided by (used in) operating activities
  $ 24,839     $ 75,282     $ 64,907     $ 44,560     $ 50,762  
(Increase) decrease in working capital
    3,342       9,010       (24,941 )     (6,796 )     21,841  
Purchase of commodity derivative contracts
    7,546       2,694                    
Amortization of costs of commodity derivative contracts
          (7,981 )     (1,219 )     (911 )      
Interest (income) expense, net
    14,843       9,929       6,038       5,058       11,129  
Unrealized (gains) losses on investment in marketable equity securities
          (5,640 )     5,640       5,640        
Loss on disposal of furniture, fixtures and equipment
                (723 )     (3 )     (575 )
Realized losses on investment in marketable equity securities
          (1,968 )     (5,246 )     (5,246 )      
Bargain purchase gain
                1,200       1,200        
Equity in earnings of Ute Energy, LLC
    7       (3,010 )     2,675       1,603       1,490  
Gain on equity share issuance
                            4,064  
                                         
Adjusted EBITDA
  $ 50,577     $ 78,316     $ 48,331     $ 45,105     $ 88,711  
                                         


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Summary Reserve and Pro Forma Operating Data
 
The following tables present summary data with respect to our estimated net proved oil and natural gas reserves and pro forma operating data as of the dates presented. The reserve estimates attributable to the Partnership Properties at December 31, 2009 presented in the table below are based on evaluations prepared by our internal reserve engineers, which have not been audited by Miller and Lents, Ltd., independent reserve engineers. The reserve estimates attributable to the Partnership Properties at June 30, 2010 are based on a report prepared by Miller and Lents, Ltd. These reserve estimates were prepared in accordance with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect. The following table also contains certain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties.
 
For a discussion of risks associated with internal reserve estimates, please read “Risk Factors — Risks Related to Our Business — Our Estimates of Proved Reserves Attributable to the Partnership Properties That Have Not Been Prepared or Reviewed By an Independent Reserve Engineering Firm May Not Be as Reliable or as Accurate as Estimated Proved Reserves Prepared by an Independent Reserve Engineering Firm” on page 37. Please also read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 112, “Business and Properties — Oil and Natural Gas Data and Operations — Partnership Properties — Estimated Proved Reserves” on page 157, and the summary of our reserve reports dated December 31, 2009 and June 30, 2010 included in this prospectus in evaluating the material presented below.
 
Reserve Data
 
                 
    Partnership Properties
    As of
  As of
    December 31,
  June 30,
    2009   2010
 
Estimated Proved Reserves:
               
Estimated net proved reserves:
               
Oil (MBbls)
    20,108       19,050  
NGLs (MBbls)
    1,629       1,488  
Natural gas (MMcf)
    56,330       54,688  
                 
Total (MBoe)(1)
    31,125       29,653  
Proved developed (MBoe)
    22,127       20,271  
Proved undeveloped (MBoe)
    8,998       9,382  
Proved developed reserves as a percentage of total proved reserves
    71 %     68 %
Standardized measure (in millions)(2)
  $ 360.1     $ 467.3  
Oil and Natural Gas Prices(3):
               
Oil — NYMEX — WTI per Bbl
  $ 61.18     $ 75.76  
Natural gas — NYMEX — Henry Hub per MMBtu
  $ 3.87     $ 4.10  
 
 
(1) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.
 
(2) Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. For a description of our commodity derivative


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contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts” on page 124.
 
(3) Our estimated net proved reserves and standardized measure were computed by applying average fiscal-year index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable twelve-month period), held constant throughout the life of the properties. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2009, the relevant average realized prices for oil, natural gas and NGLs were $56.46 per Bbl, $3.75 per Mcf and $33.12 per Bbl, respectively. As of June 30, 2010, the relevant average realized prices for oil, natural gas and NGLs were $71.49 per Bbl, $3.49 per Mcf and $44.53 per Bbl, respectively.
 
Pro Forma Operating Data
 
                         
    QR Energy, LP
    Pro Forma
    Year Ended
  Nine Months Ended
    December 31,
  September 30,
    2009   2009   2010
 
Net Production:
                       
Total production (MBoe)
    1,927       1,452       1,415  
Average production (Boe/d)
    5,280       5,319       5,184  
Average Sales Price per Boe(1)
  $ 39.91     $ 36.74     $ 52.51  
Average Unit Costs per Boe:
                       
Oil and natural gas production expenses
  $ 12.34     $ 11.63     $ 10.77  
Production taxes
  $ 2.99     $ 1.98     $ 2.35  
Fund management fees
  $     $     $  
General and administrative expenses
  $ 5.85     $ 6.73     $ 8.71  
Depletion, depreciation and amortization
  $ 12.66     $ 12.63     $ 12.96  
 
 
(1) Pro forma average sales prices per Boe do not include gains or losses on commodity derivative contracts. Because the commodity derivative contracts to be contributed to us have been commingled with the properties retained by our predecessor, the pro forma information associated with these commodity derivative contracts is not available by product type. Though we are able to calculate pro forma average sales prices per Boe including gains or losses on commodity derivative contracts, such a presentation would not be comparable to pro forma average sales prices by product type presented elsewhere in this prospectus that omit gains or losses on commodity derivative contracts. Accordingly, we have omitted the effects of commodity derivative contracts from our pro forma average sales prices per Boe.


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RISK FACTORS
 
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. Prospective unitholders should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.
 
If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment.
 
Risks Related to Our Business
 
We May Not Have Sufficient Cash to Pay the Minimum Quarterly Distribution on Our Common Units, Following the Establishment of Cash Reserves and Payment of Fees and Expenses, Including Payments to Our General Partner.
 
We may not have sufficient available cash each quarter to pay the minimum quarterly distribution of $0.4125 per unit or any other amount.
 
Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. We intend to reserve a portion of our cash generated from operations to develop our oil and natural gas properties and to acquire additional oil and natural gas properties to maintain and grow our oil and natural gas reserves.
 
The amount of cash we actually generate will depend upon numerous factors related to our business that may be beyond our control, including, among other things, the risks described in this section.
 
In addition, the actual amount of cash that we will have available for distribution to our unitholders will depend on other factors, including:
 
  •  the amount of oil, NGLs and natural gas we produce;
 
  •  the prices at which we sell our oil, NGL and natural gas production;
 
  •  the effectiveness of our commodity price hedging strategy;
 
  •  the cost to produce our oil and natural gas assets;
 
  •  the level of our capital expenditures, including scheduled and unexpected maintenance expenditures;
 
  •  the cost of acquisitions;
 
  •  our ability to borrow funds under our new credit facility;
 
  •  prevailing economic conditions;
 
  •  sources of cash used to fund acquisitions;
 
  •  debt service requirements and restrictions on distributions contained in our new credit facility or future debt agreements;
 
  •  interest payments;


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  •  fluctuations in our working capital needs;
 
  •  general and administrative expenses, including expenses we will incur as a result of being a public company; and
 
  •  the amount of cash reserves, which we expect to be substantial, established by our general partner for the proper conduct of our business.
 
As a result of these factors, the amount of cash we distribute to our unitholders may fluctuate significantly from quarter to quarter and may be less than the minimum quarterly distribution that we expect to distribute. For a description of additional restrictions and factors that may affect our ability to make cash distributions to our unitholders, please read “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 70.
 
We Would Not Have Generated Sufficient Available Cash on a Pro Forma Basis to Have Paid the Minimum Quarterly Distribution on All of Our Units for the Year Ended December 31, 2009 or the Twelve Months Ended September 30, 2010.
 
We must generate approximately $59.0 million of available cash to pay the minimum quarterly distribution for four quarters on all of our common units, subordinated units and general partner units that will be outstanding immediately after this offering. If we had completed the formation transactions contemplated in this prospectus and the acquisition of all of the Partnership Properties on January 1, 2009, our unaudited pro forma available cash for the year ended December 31, 2009 would have been approximately $47.7 million. This amount would not have been sufficient to make a cash distribution for the year ended December 31, 2009 at the minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units, subordinated units, and general partner units. Specifically, this amount would have been sufficient to allow us to pay the full minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units, but only a cash distribution of $0.0190 per unit per quarter (or $0.08 per unit on an annualized basis) on all of the subordinated units, or approximately 4.6% of the minimum quarterly distribution. If we had completed the transactions contemplated in this prospectus and the acquisition of all of our properties on October 1, 2009, our unaudited pro forma available cash for the twelve months ended September 30, 2010 would have been approximately $51.3 million. This amount would not have been sufficient to make a cash distribution for the twelve months ended September 30, 2010 at the minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units, subordinated units, and general partner units. Specifically, this amount would have been sufficient to allow us to pay the full minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units, but only a cash distribution of $0.1447 per unit per quarter (or $0.58 per unit on an annualized basis) on all of the subordinated units, or approximately 35.1% of the minimum quarterly distribution. While the fourth quarter is not complete, based on our internal preliminary results of operations, we estimate that available cash generated during the three months ending December 31, 2010 would not have been sufficient to make a cash distribution at the minimum quarterly distribution of $0.4125 per unit on all of the common units, subordinated units, and general partner units if such units had been outstanding during the entire fourth quarter of 2010. For a calculation of our ability to have made distributions to unitholders based on our pro forma results of operations for the year ended December 31, 2009 and the twelve months ended September 30, 2010, please read “Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Available Cash for the Year Ended December 31, 2009 and the Twelve Months Ended September 30, 2010” on page 74.


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Our Estimate of the Minimum Adjusted EBITDA Necessary for Us to Make a Distribution on All Units at the Minimum Quarterly Distribution for Each of the Four Quarters Ending December 31, 2011 Is Based on Assumptions That Are Inherently Uncertain and Are Subject to Significant Business, Economic, Financial, Legal, Regulatory and Competitive Risks and Uncertainties That Could Cause Actual Results to Differ Materially from Those Estimated.
 
Our estimate of the minimum Adjusted EBITDA necessary for us to make a distribution on all units at the minimum quarterly distribution for each of the four quarters ending December 31, 2011, as set forth in “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 70 is based on our management’s calculations, and we have neither received nor requested an opinion or report on the estimate from our or any other independent auditor. This estimate is based on our June 30, 2010 reserve report, which reflects assumptions about development, production, oil and natural gas prices and capital expenditures, and other assumptions about expenses, borrowings and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. If any of these assumptions prove to be inaccurate, our actual results may differ materially from those set forth in our estimates, and we may be unable to pay all or part of the minimum quarterly distribution on our common units, subordinated units or general partner units, in which event the market price of our common units may decline materially. For prospective financial information regarding our ability to pay the full minimum quarterly distribution on our common units, subordinated units and general partner units for the twelve months ended September 30, 2010, please read “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 70.
 
Our Estimated Oil and Natural Gas Reserves Will Naturally Decline Over Time, and It Is Unlikely That We Will Be Able to Sustain Distributions at the Level of Our Minimum Quarterly Distribution Without Making Accretive Acquisitions or Substantial Capital Expenditures That Maintain Our Asset Base.
 
Our future oil and natural gas reserves, production volumes, cash flow and ability to make distributions to our unitholders depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. Based on our June 30, 2010 reserve report, the average decline rate for our existing proved developed producing reserves is approximately 10% for 2011, approximately 9% compounded average decline for the subsequent five years and approximately 8% thereafter. 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, financial condition and results of operations and reduce cash available for distribution to our unitholders.
 
We will need to make substantial capital expenditures to maintain our asset base, which will reduce our cash available for distribution. Because the timing and amount of these capital expenditures may fluctuate each quarter, we expect to reserve substantial amounts of cash each quarter to finance these expenditures over time. For example, we plan to spend approximately $3.7 million for capital expenditures for the twelve months ending December 31, 2011 based on our reserve report dated June 30, 2010, but will reserve an additional $8.8 million during 2011 to maintain the current level of production from our assets. We estimate that an average annual capital expenditure of $12.5 million will enable us to maintain the current level of production from our assets through December 31, 2015. We may use the reserved cash to reduce indebtedness until we make the capital expenditures. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the minimum quarterly distribution from cash generated from operations and would therefore expect to reduce our distributions. If our reserves decrease and we do not reduce our distribution, then a portion of the distribution may be considered a return of part of a unitholder’s investment in us as opposed to a return on his investment. If we do not make sufficient growth capital expenditures, we will be unable to sustain our business operations and would therefore expect to reduce our distributions to our unitholders. We have not forecasted any growth


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capital expenditures for the twelve months ending December 31, 2011, based on our reserve report dated June 30, 2010.
 
None of the Proceeds of This Offering Will Be Used to Maintain or Grow Our Asset Base or Be Reserved for Future Distributions.
 
None of the proceeds of this offering will be used to maintain or grow our asset base, which may be necessary to cover future distributions to our unitholders, and none of the proceeds will be reserved for future distributions to our unitholders. The proceeds of this offering, together with borrowings under our new credit facility, will be used as partial consideration for the assets contributed to us by the Fund in connection with this offering.
 
Our Acquisition and Development Operations Will Require Substantial Capital Expenditures. We Expect to Fund These Capital Expenditures Using Cash Generated from Our Operations, Additional Borrowings or the Issuance of Additional Partnership Interests, or Some Combination Thereof, Which Could Adversely Affect Our Ability to Pay Distributions at the Then-Current Distribution Rate or at All.
 
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial growth capital expenditures in our business for the development, production and acquisition of oil and natural gas reserves. These expenditures will reduce the amount of cash available for distribution to our unitholders. We intend to finance our future growth capital expenditures with cash flows from operations, borrowings under new our credit facility and the issuance of debt and equity securities.
 
Our cash flows from operations and access to capital are subject to a number of variables, including:
 
  •  our estimated proved oil and natural gas reserves;
 
  •  the amount of oil, NGL and natural gas we produce from existing wells;
 
  •  the prices at which we sell our production;
 
  •  the costs of developing and producing our oil and natural gas production;
 
  •  our ability to acquire, locate and produce new reserves;
 
  •  the ability and willingness of banks to lend to us; and
 
  •  our ability to access the equity and debt capital markets.
 
The use of cash generated from operations to fund growth capital expenditures will reduce cash available for distribution to our unitholders. If the borrowing base under our new credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in estimated reserves or production or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed to fund our growth capital expenditures, our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.
 
Our failure to obtain the funds for necessary future growth capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions to our unitholders. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution, thereby increasing the


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aggregate amount of cash required to maintain the then-current distribution rate, which could adversely affect our ability to pay distributions to our unitholders at the then-current distribution rate or at all.
 
Oil and Natural Gas Prices Are Very Volatile. A Decline in Oil or Natural Gas Prices Will Cause a Decline in Our Cash Flow from Operations, Which Could Cause Us to Reduce Our Distributions or Cease Paying Distributions Altogether.
 
The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. 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:
 
  •  domestic and foreign supply of and demand for oil and natural gas;
 
  •  weather conditions and the occurrence of natural disasters;
 
  •  overall domestic and global economic conditions;
 
  •  political and economic conditions in oil and natural gas producing countries globally, including terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war;
 
  •  actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state-controlled oil companies relating to oil price and production controls;
 
  •  the effect of increasing liquefied natural gas, or LNG, deliveries to and exports from the United States;
 
  •  the impact of the U.S. dollar exchange rates on oil and natural gas prices;
 
  •  technological advances affecting energy supply and energy consumption;
 
  •  domestic and foreign governmental regulations and taxation;
 
  •  the impact of energy conservation efforts;
 
  •  the proximity, capacity, cost and availability of oil and natural gas pipelines and other transportation facilities;
 
  •  the availability of refining capacity; and
 
  •  the price and availability of alternative fuels.
 
In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2009, the NYMEX–WTI oil price ranged from a high of $81.04 per Bbl to a low of $33.98 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $6.11 per MMBtu to a low of $1.88 per MMBtu. For the five years ended December 31, 2009, the NYMEX–WTI oil price ranged from a high of $145.29 per Bbl to a low of $31.41 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $15.39 per MMBtu to a low of $1.88 per MMBtu.
 
Our revenue, profitability and cash flow depend upon the prices of and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:
 
  •  limit our ability to enter into commodity derivative contracts at attractive prices;
 
  •  negatively impact the value and quantities of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can economically produce;
 
  •  reduce the amount of cash flow available for capital expenditures;
 
  •  limit our ability to borrow money or raise additional capital; and


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  •  impair our ability to pay distributions to our unitholders.
 
If we raise our distribution levels in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during subsequent periods of lower commodity prices.
 
An Increase in the Differential Between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Significantly Reduce Our Cash Available for Distribution and Adversely Affect Our Financial Condition.
 
The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price we receive could significantly reduce our cash available for distribution to our unitholders and adversely affect our financial condition. We do not have or plan to have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials, which could adversely affect our results of operations.
 
Future Price Declines May Result in a Write-Down of the Carrying Values of Our Oil and Natural Gas Properties, Which Could Adversely Affect Our Results of Operations.
 
We may be required under full cost accounting rules to write down the carrying value of our oil and natural gas properties if oil and natural gas prices decline or if we have substantial downward adjustments to our estimated proved reserves, capital expenditures that do not generate equivalent or greater value in estimated proved reserves, increases in our estimated future operating, development or abandonment costs or deterioration in our exploration results.
 
We utilize the full cost method of accounting for oil and natural gas exploration and development activities. Under this method, all costs associated with property exploration and development (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and direct overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. Under full cost accounting, we are required by SEC regulations to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of our oil and natural gas properties that is equal to the expected present value (discounted at 10%) of the future net cash flows from estimated proved reserves, including the effect of cash flow hedges, if applicable, calculated using the applicable price calculation for the period tested, as adjusted for “basis” or location differentials, or net wellhead prices held constant over the life of the reserves. Under current rules, which became effective for ceiling tests on the year ended December 31, 2009, the ceiling limitation calculation uses the SEC methodology to calculate the present value of future net cash flows from estimated proved reserves. For prior periods, the ceiling limitation calculation used oil and natural gas prices in effect as of the balance sheet date, as adjusted for basis or location differentials as of the balance sheet date, and held constant over the life of the reserves. If the net book value of our oil and natural gas properties exceeds our ceiling limitation, SEC regulations require us to impair or “write down” the book value of our oil and natural gas properties. For example, due to continued declines in oil and natural gas prices at both March 31, 2009 and December 31, 2008, capitalized costs on our predecessor’s estimated proved oil and natural gas properties exceeded its ceiling, resulting in non-cash write-downs of $28.3 million and $451.4 million, respectively. Depending on the magnitude of any future impairments, a ceiling test write-down could significantly reduce our net income, or produce a net loss.
 
A ceiling test write-down would not impact cash flow from operating activities, but it would reduce partners’ equity on our balance sheet. The risk of a required ceiling test write-down of the book value of oil and natural gas properties increases when oil and natural gas prices are low. We may incur


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impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred.
 
Our Hedging Strategy May Be Ineffective in Removing the Impact of Commodity Price Volatility from Our Cash Flows, Which Could Result in Financial Losses or Could Reduce Our Income, Which May Adversely Affect Our Ability to Pay Distributions to Our Unitholders.
 
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, the Fund will contribute to us at the closing of this offering, and we may in the future enter into, commodity derivative contracts for a significant portion of our oil and natural gas production that could result in both realized and unrealized hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity derivative contracts. For example, some of the commodity derivative contracts we utilize are based on quoted market prices, which may differ significantly from the actual prices we realize in our operations for oil and natural gas. We also expect to enter into a credit facility, that, among other things, will limit the amount of commodity derivative contracts we can enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. For the years ending December 31, 2011, 2012, 2013, 2014 and 2015, approximately 20%, 29%, 32%, 35% and 53%, respectively, of our pro forma estimated total oil and natural gas production, based on our reserve report dated June 30, 2010, will not be covered by commodity derivative contracts. In addition, none of our pro forma estimated total NGL production is covered by commodity derivative contracts at the closing of this offering. Likewise, we do not have or plan to have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials, which could adversely affect our results of operations. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Quantitative and Qualitative Disclosure About Market Risk” beginning on page 125.
 
We expect to adopt a hedging policy to reduce the impact to our cash flows from commodity price volatility under which we intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated oil and natural gas production over a three-to-five year period at a given point of time. As opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative contracts in connection with material increases in our estimated reserves and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. However, our price hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under an obligation to enter into commodity derivative contracts covering a specific portion of our production. The prices at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.
 
In addition, our actual future production may be significantly higher or lower than we estimate at the time we enter into commodity derivative contracts for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the notional amount of our commodity derivative contracts, we might be forced to satisfy all or a portion of our commodity derivative contracts without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, substantially diminishing our liquidity. There may be


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a change in the expected differential between the underlying commodity price in the commodity derivative contract and the actual price received, which may result in payments to our derivative counterparty that are not offset by our receipt of higher prices from our production in the field.
 
As a result of these factors, our commodity derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows, which could adversely affect our ability to pay distributions to our unitholders.
 
Our Hedging Transactions Expose Us to Counterparty Credit Risk.
 
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.
 
Our Estimated Proved Reserves Are Based on Many Assumptions That May Prove to Be Inaccurate. Any Material Inaccuracies in These Reserve Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Estimated Reserves.
 
It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs. In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:
 
  •  the level of oil and natural gas prices;
 
  •  future production levels;
 
  •  capital expenditures;
 
  •  operating and development costs;
 
  •  the effects of regulation;
 
  •  the accuracy and reliability of the underlying engineering and geologic data; and
 
  •  the availability of funds.
 
If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our estimated proved reserves could change significantly. For example, if the prices used in our June 30, 2010 reserve report had been $10.00 less per barrel for oil and $1.00 less per Mcf for natural gas, then the standardized measure of our estimated proved reserves as of that date on a pro forma basis would have decreased by $108.2 million, from $467.3 million to $359.1 million.
 
Our standardized measure is calculated using unhedged oil, natural gas and NGL prices and is determined in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.
 
The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may


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contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.
 
The Standardized Measure of Our Estimated Proved Reserves is Not Necessarily the Same As the Current Market Value of Our Estimated Proved Oil and Natural Gas Reserves.
 
The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect as of the date of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:
 
  •  the actual prices we receive for oil, natural gas and NGLs;
 
  •  our actual operating costs in producing oil, natural gas and NGLs;
 
  •  the amount and timing of actual production;
 
  •  the amount and timing of our capital expenditures;
 
  •  the supply of and demand for oil, natural gas and NGLs; and
 
  •  changes in governmental regulations or taxation.
 
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with Accounting Standards Codification 932, “Extractive Activities — Oil and Natural Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
 
Our Estimates of Proved Reserves Attributable to the Partnership Properties That Have Not Been Prepared or Audited By an Independent Reserve Engineering Firm May Not Be As Reliable or As Accurate As Estimates of Proved Reserves Prepared By an Independent Reserve Engineering Firm.
 
Estimates of proved oil and natural gas reserves are inherently uncertain, and any material inaccuracies in our reserve estimates will materially affect the quantities and values of our reserves. The estimates of the proved reserves attributable to the Partnership Properties as of December 31, 2009 included in this prospectus were prepared by our internal reserve engineers and professionals. Our internal estimates of proved reserves may differ materially from independent proved reserve estimates as a result of the estimation process employed by an independent reserve engineering firm. Our internal proved reserve estimates are based upon various assumptions, including assumptions required by the SEC related to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our internal proved reserve estimates may not be indicative of or may differ materially from the estimates of our proved reserves as of December 31, 2010 that will be prepared by Miller & Lents, Ltd.
 
Secondary and Tertiary Recovery Techniques May Not Be Successful, Which Could Adversely Affect Our Financial Condition or Results of Operations and, As a Result, Our Ability to Pay Distributions to Our Unitholders.
 
Approximately 60% of our pro forma production for the nine months ended September 30, 2010 and 60% of our pro forma estimated proved reserves as of June 30, 2010 relied on secondary and tertiary recovery techniques, which include waterfloods and injecting gases into producing formations to enhance hydrocarbon recovery. If production response to these techniques is less than forecasted for a particular project, then the project may be uneconomic or generate less cash flow and reserves than we


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had estimated prior to investing the capital to employ these techniques. Risks associated with secondary and tertiary recovery techniques include the following:
 
  •  lower-than-expected production;
 
  •  longer response times;
 
  •  higher-than-expected operating and capital costs;
 
  •  shortages of equipment; and
 
  •  lack of technical expertise.
 
If any of these risks occur, it could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
 
Developing and Producing Oil and Natural Gas Are Costly and High-Risk Activities with Many Uncertainties That Could Adversely Affect Our Financial Condition or Results of Operations and, As a Result, Our Ability to Pay Distributions to Our Unitholders.
 
The cost of developing, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated. Furthermore, our development and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
 
  •  high costs, shortages or delivery delays of rigs, equipment, labor or other services;
 
  •  composition of sour gas, including sulfur and mercaptan content;
 
  •  unexpected operational events and conditions;
 
  •  reductions in oil and natural gas prices;
 
  •  increases in severance taxes;
 
  •  adverse weather conditions and natural disasters;
 
  •  facility or equipment malfunctions and equipment failures or accidents, including acceleration of deterioration of our facilities and equipment due to the highly corrosive nature of sour gas;
 
  •  title problems;
 
  •  pipe or cement failures and casing collapses;
 
  •  compliance with environmental and other governmental requirements;
 
  •  environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
 
  •  lost or damaged oilfield development and service tools;
 
  •  unusual or unexpected geological formations and pressure or irregularities in formations;
 
  •  loss of drilling fluid circulation;
 
  •  fires, blowouts, surface craterings and explosions;
 
  •  uncontrollable flows of oil, natural gas or well fluids;
 
  •  loss of leases due to incorrect payment of royalties; and
 
  •  other hazards, including those associated with sour gas such as an accidental discharge of hydrogen sulfide gas, that could also result in personal injury and loss of life, pollution and suspension of operations.


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If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and cash available for distribution to our unitholders.
 
Additionally, drilling, transportation and processing of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with the affected wellbore, contamination of soil, ground water, and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences.
 
Our Expectations for Future Drilling Activities Are Planned to Be Realized Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Such Activities.
 
We have identified drilling, recompletion and development locations and prospects for future drilling, recompletion and development. These drilling, recompletion and development locations represent a significant part of our future drilling and enhanced recovery opportunity plans. Our ability to drill, recomplete and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs and drilling results. Because of these uncertainties, we cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of estimated proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our estimated reserves, financial condition and results of operations.
 
Shortages of Rigs, Equipment and Crews Could Delay Our Operations and Reduce Our Cash Available for Distribution to Our Unitholders.
 
Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and reduce our cash available for distribution to our unitholders.
 
If We Do Not Make Acquisitions on Economically Acceptable Terms, Our Future Growth and Ability to Pay or Increase Distributions Will Be Limited.
 
Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:
 
  •  unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners;
 
  •  unable to obtain financing for these acquisitions on economically acceptable terms; or
 
  •  outbid by competitors.
 
If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions to our unitholders.


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Any Acquisitions We Complete Are Subject to Substantial Risks That Could Reduce Our Ability to Make Distributions to Unitholders.
 
Even if we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:
 
  •  the validity of our assumptions about estimated proved reserves, future production, revenues, capital expenditures, operating expenses and costs, including synergies;
 
  •  an inability to successfully integrate the businesses we acquire;
 
  •  a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
 
  •  a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
 
  •  the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
 
  •  the diversion of management’s attention from other business concerns;
 
  •  an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
 
  •  facts and circumstances that could give rise to significant cash and certain non-cash charges;
 
  •  unforeseen difficulties encountered in operating in new geographic areas; and
 
  •  customer or key employee losses at the acquired businesses.
 
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
 
Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition, given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.
 
If our acquisitions do not generate the expected increases in available cash per unit, our ability to make distributions to our unitholders could be reduced.
 
We May Experience a Financial Loss If Quantum Resources Management Is Unable to Sell a Significant Portion of Our Oil and Natural Gas Production.
 
Under our services agreement, Quantum Resources Management will sell our oil, natural gas and NGL production on our behalf. Quantum Resources Management’s ability to sell our production depends upon the demand for oil, natural gas and NGLs from Quantum Resources Management’s customers.
 
In recent years, a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for the Fund’s and our production. This reduction in potential customers has reduced overall market liquidity. If any one or more of Quantum Resources Management’s significant customers reduces the volume of oil and natural gas production it purchases and Quantum Resources Management is unable to sell those volumes to other customers, then the volume of our production that Quantum Resources


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Management sells on our behalf could be reduced, and we could experience a material decline in cash available for distribution.
 
In addition, a failure by any of these companies, or any purchasers of our production, to perform their payment obligations to us could have a material adverse effect on our results of operation. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and ability to make distributions to our unitholders.
 
We May Be Unable to Compete Effectively with Larger Companies, Which May Adversely Affect Our Ability to Generate Sufficient Revenue to Allow Us to Pay Distributions to Our Unitholders.
 
The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Many of our competitors are large independent oil and natural gas companies that possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.
 
We May Incur Substantial Additional Debt to Enable Us to Pay Our Quarterly Distributions, Which May Negatively Affect Our Ability to Pay Future Distributions or Execute Our Business Plan.
 
We may be unable to pay the minimum quarterly distribution or the then-current distribution rate without borrowing under our new credit facility. When we borrow to pay distributions to our unitholders, we are distributing more cash than we are generating from our operations on a current basis. This means that we are using a portion of our borrowing capacity under our new credit facility to pay distributions to our unitholders rather than to maintain or expand our operations. If we use borrowings under our new credit facility to pay distributions to our unitholders for an extended period of time rather than to fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to pay distributions to our unitholders during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution to our unitholders to avoid excessive leverage.
 
Our Future Debt Levels May Limit Our Ability to Obtain Additional Financing and Pursue Other Business Opportunities.
 
After giving effect to this offering and the related transactions, we estimate that we would have had approximately $225 million of debt outstanding on a pro forma basis as of September 30, 2010. Following


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the consummation of this offering, we expect that we will have the ability to incur debt, including under a new credit facility we expect to enter into in connection with this offering, subject to anticipated borrowing base limitations in our credit facility. The level of our future indebtedness could have important consequences to us, including:
 
  •  our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
 
  •  covenants contained in our new credit agreement and future debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
 
  •  we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to our unitholders; and
 
  •  our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
 
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions to our unitholders, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all, which may have an adverse effect on our ability to reduce cash distributions.
 
Our New Credit Facility Will Have Substantial Restrictions and Financial Covenants That May Restrict Our Business and Financing Activities and Our Ability to Pay Distributions to Our Unitholders.
 
The operating and financial restrictions and covenants in our new credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — New Credit Facility” on page 123. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit facility that are not cured or waived within the appropriate time periods provided in our new credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.
 
We anticipate that our new credit facility will be reserve-based, and thus we will be permitted to borrow under our new credit facility in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base will be subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, NGL and oil reserves, which will take into account the prevailing natural gas, NGL and oil


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prices at such time, as adjusted for the impact of our commodity derivative contracts. In the future, we may be unable to access sufficient capital under our new credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.
 
A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our new credit facility. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under our new credit facility.
 
Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured.
 
There are a variety of operating risks inherent in our wells, gathering systems, pipelines, natural gas processing plants and other facilities, such as leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses. The location of our wells, gathering systems, pipelines, natural gas processing plants and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.
 
Insurance against all operational risk is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to weather and adverse economic conditions have made it more difficult for us to obtain certain types of coverage. Further, we anticipate further tightening of the insurance markets in the aftermath of the Macondo well incident in the Gulf of Mexico in April 2010. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and we cannot be sure the insurance coverage we do obtain will contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.
 
Our Business Depends In Part on Pipelines, Gathering Systems and Processing Facilities Owned By Others. Any Limitation in the Availability of Those Facilities Could Interfere with Our Ability to Market Our Oil and Natural Gas Production and Could Harm Our Business.
 
The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines, gathering systems and processing facilities. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. 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


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curtailment in gathering system or pipeline or processing facility capacity could reduce our ability to market our oil and natural gas production and harm our business.
 
Because We Do Not Control the Development of Certain of the Properties in Which We Own Interests, but Do Not Operate, Including Our Overriding Oil Royalty Interest in the Jay Field, We May Not Be Able to Achieve Any Production from These Properties in a Timely Manner.
 
As of June 30, 2010, approximately 5.1 MMBoe of our estimated proved reserves and 1.4 MMBoe of our estimated proved undeveloped reserves, or approximately 17% of our estimated proved reserves and 15% of our estimated proved undeveloped reserves as determined by volume and by value based on standardized measure, were attributable to properties for which we were not the operator, including our overriding oil royalty interest in the Jay Field. As a result, the success and timing of drilling and development activities on such nonoperated properties depend upon a number of factors, including:
 
  •  the nature and timing of drilling and operational activities;
 
  •  the timing and amount of capital expenditures;
 
  •  the operators’ expertise and financial resources;
 
  •  the approval of other participants in such properties; and
 
  •  the selection and application of suitable technology.
 
If drilling and development activities are not conducted on these properties or are not conducted on a timely basis, we may be unable to increase our production or offset normal production declines, or we will be required to write off the estimated proved reserves attributable thereto, any of which may adversely affect our production, revenues and results of operations and our cash available for distribution. Any such write-offs of our reserves could reduce our ability to borrow money and could adversely impact our ability to pay distributions on the common units.
 
Our Historical and Pro Forma Financial Information May Not Be Representative of Our Future Performance.
 
The historical financial information included in this prospectus is derived from our historical financial statements for periods prior to our initial public offering. Our audited historical financial statements were prepared in accordance with GAAP. Accordingly, the historical financial information included in this prospectus does not reflect what our results of operations and financial condition would have been had we been a public entity during the periods presented, or what our results of operations and financial condition will be in the future.
 
In preparing the unaudited pro forma financial information included in this prospectus, we have made adjustments to our historical financial information based upon currently available information and upon assumptions that our management believes are reasonable in order to reflect, on a pro forma basis, the impact of the items discussed in our unaudited pro forma financial statements and related notes. The estimates and assumptions used in the calculation of the pro forma financial information in this prospectus may be materially different from our actual experience as a public entity. Accordingly, the pro forma financial information included in this prospectus does not purport to represent what our results of operations would actually have been had the transactions which are reflected in our unaudited pro forma financial statements actually taken place, nor does it represent what our results of operations would have been had we operated as a public entity during the periods presented. The pro forma financial information also does not purport to represent what our results of operations and financial condition will be in the future, nor does the unaudited pro forma financial information give effect to any events other than those discussed in our unaudited pro forma financial statements and related notes.


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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, production and processing operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.
 
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 production and processing 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, financial condition, results of operations and ability to make distributions to our unitholders. Please read “Business and Properties — Environmental Matters and Regulation” beginning on page 163 and “— Other Regulation of the Oil and Natural Gas Industry” on page 167 for a description of the laws and regulations that affect us.
 
Climate Change Legislation or Regulations Restricting Emissions of “Greenhouse Gases” Could Result in Increased Operating Costs and Reduced Demand for the Oil and Natural Gas That We Produce.
 
On December 15, 2009, the U.S. Environmental Protection Agency, or EPA published its findings that emissions of carbon dioxide, or CO2, methane, and other greenhouse gases, or GHGs, present an endangerment to public heath and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the existing Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, in April 2010, the EPA proposed to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. If the proposed rule is finalized as proposed, reporting of GHG emissions from such facilities would be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.
 
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Please read “Business and Properties — Environmental Matters and Regulation” beginning on page 163.
 
Our Operations Are Subject to Environmental and Operational Safety Laws and Regulations That May Expose Us to Significant Costs and Liabilities.
 
Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition


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of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations.
 
There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our business, financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance. Please read “Business and Properties — Environmental Matters and Regulation” beginning on page 163 for more information.
 
The Third Parties on Whom We Rely for Gathering and Transportation Services Are Subject to Complex Federal, State and Other Laws That Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business.
 
The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. Please read “Business and Properties — Environmental Matters and Regulation” beginning on page 163 and “Business and Properties — Other Regulation of the Oil and Natural Gas Industry” on page 167 for a description of the laws and regulations that affect the third parties on whom we rely.
 
The Recent Adoption of Derivatives Legislation By the United States Congress Could Have an Adverse Effect on Our Ability to Use Derivative Contracts to Reduce the Effect of Commodity Price, Interest Rate and Other Risks Associated with Our Business.
 
The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that


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participate in that market. The Commodity Futures Trading Commission, or the CFTC, has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative contracts to spin off some of their derivatives contracts to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.
 
Federal and State Legislative and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.
 
Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion of certain oil and natural gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production. This process is typically regulated by state oil and natural gas agencies and has not been subject to federal regulation. However, due to concerns that hydraulic fracturing may adversely affect drinking water supplies, the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into hydraulic fracturing practices. Additionally, legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to subject hydraulic fracturing processes to regulation under that Act and to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. If enacted, such a provision could require hydraulic fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping requirements and meet plugging and abandonment requirements.
 
In unrelated oil spill legislation being considered by the U.S. Senate in the aftermath of the April 2010 Macondo well release in the Gulf of Mexico, Senate Majority Leader Harry Reid has added a requirement that natural gas drillers disclose the chemicals they pump into the ground as part of the hydraulic fracturing process. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Adoption of legislation or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on our exploration and production activities, which could make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced, as well as increase our costs of compliance and doing business.


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Increases in Interest Rates Could Adversely Impact Our Unit Price and Our Ability to Issue Additional Equity and Incur Debt.
 
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and implied distribution yield. The distribution yield is often used by investors to compare and rank similar yield oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt.
 
Risks Inherent in an Investment in Us
 
Our General Partner and Its Affiliates Own a Controlling Interest in Us and Will Have Conflicts of Interest with, and Owe Limited Fiduciary Duties to, Us, Which May Permit Them to Favor Their Own Interests to the Detriment of Our Unitholders.
 
Our general partner will have control over all decisions related to our operations. Upon consummation of this offering, the Fund will control an aggregate of approximately 47.5% of our outstanding common units and all of our subordinated units, and our general partner will be owned 50% by an entity controlled by Mr. Neugebauer and Mr. VanLoh, who are directors of our general partner and also managing partners of Quantum Energy Partners, and 50% by an entity controlled by Mr. Smith, our Chief Executive Officer, a director of our general partner and Chief Executive Officer and a director of Quantum Resources Management, and Mr. Campbell, our President and Chief Operating Officer, a director of our general partner and President, Chief Operating Officer and a director of Quantum Resources Management. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, certain directors and officers of our general partner are directors or officers of affiliates of our general partner, including Quantum Resources Management and Quantum Energy Partners, and certain of our executive officers and directors will continue to have economic interests, investments and other economic incentives in funds affiliated with Quantum Energy Partners. Conflicts of interest may arise in the future between the Fund, Quantum Energy Partners and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. Please read “— Our Partnership Agreement Limits Our General Partner’s Fiduciary Duties to Unitholders and Restricts the Remedies Available to Unitholders for Actions Taken By Our General Partner That Might Otherwise Constitute Breaches of Fiduciary Duty” on page 56. These potential conflicts include, among others, the following situations:
 
  •  neither our partnership agreement nor any other agreement requires the Fund, Quantum Energy Partners or their respective affiliates (other than our general partner) to pursue a business strategy that favors us. The directors and officers of the Fund, Quantum Energy Partners and their respective affiliates (other than our general partner) have a fiduciary duty to make these decisions in the best interests of their respective equity holders, which may be contrary to our interests;
 
  •  our general partner is allowed to take into account the interests of parties other than us, such as the owners of our general partner, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
 
  •  the Fund, Quantum Energy Partners and their affiliates are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer assets to us except for the obligations of the Fund and its general partner under our omnibus agreement. Please read “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest — Other Than Certain Obligations of the Fund and Its General Partner With Respect to


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  Our Omnibus Agreement, the Fund, Quantum Energy Partners and Other Affiliates of Our General Partner Will Not Be Limited in Their Ability to Compete With Us, Which Could Limit Our Ability to Acquire Additional Assets or Businesses” on page 194;
 
  •  many of the officers of our general partner who will provide services to us will devote time to affiliates of our general partner, including Quantum Resources Management and Quantum Energy Partners, and may be compensated for services rendered to such affiliates;
 
  •  our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
 
  •  our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;
 
  •  our general partner will enter into a services agreement with Quantum Resources Management in connection with this offering, pursuant to which Quantum Resources Management will operate our assets and perform other administrative services for us. Quantum Resources Management has similar arrangements with affiliates of the Fund;
 
  •  after December 31, 2012, our general partner will determine which costs, including allocated overhead, incurred by it and its affiliates, including Quantum Resources Management, are reimbursable by us. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to 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 and, in some circumstances, is entitled to be indemnified by us;
 
  •  our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;
 
  •  our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including Quantum Resources Management and the Fund; and
 
  •  our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
Please read “Certain Relationships and Related Party Transactions” beginning on page 183 and “Conflicts of Interest and Fiduciary Duties” beginning on page 193.
 
The Fund, Quantum Energy Partners and Other Affiliates of Our General Partner Will Not Be Limited in Their Ability to Compete with Us, Which Could Cause Conflicts of Interest and Limit Our Ability to Acquire Additional Assets or Businesses.
 
Our partnership agreement provides that the Fund and Quantum Energy Partners and their respective affiliates are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, except for the limited obligations of the Fund described below with respect to our omnibus agreement, the Fund and Quantum Energy Partners and their respective


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affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Under the terms of our omnibus agreement, the Fund will only be obligated to offer us the first option to acquire 25% of each acquisition that becomes available to the Fund, so long as at least 70% of the allocated value (as determined in good faith by the Fund) is attributable to proved developed producing reserves. In addition, the terms of our omnibus agreement require the Fund to give us a preferential opportunity to bid on any oil or natural gas properties that the Fund intends to sell only if such properties are at least 70% proved developed producing reserves (as determined in good faith by the Fund). In addition to opportunities to purchase additional properties from, and to participate in future acquisition opportunities with, the Fund, the general partner of the Fund will agree that, if it or its affiliates establish another fund to acquire oil and natural gas properties within two years of the closing of this offering, it will cause such fund to provide us with a similar right to participate in such fund’s acquisition opportunities. These provisions of the omnibus agreement will expire five years after the closing of this offering.
 
The Fund and Quantum Energy Partners are established participants in the oil and natural gas industry, and have resources greater than ours, which factors may make it more difficult for us to compete with the Fund and Quantum Energy Partners with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. Please read “Conflicts of Interest and Fiduciary Duties” beginning on page 193.
 
Neither We Nor Our General Partner Have Any Employees and We Rely Solely on the Employees of Quantum Resources Management to Manage Our Business. Quantum Resources Management Will Also Provide Substantially Similar Services to the Fund, and Thus Will Not Be Solely Focused on Our Business.
 
Neither we nor our general partner have any employees and we rely solely on Quantum Resources Management to operate our assets. Upon consummation of this offering, our general partner will enter into a services agreement with Quantum Resources Management, pursuant to which Quantum Resources Management has agreed to make available to our general partner Quantum Resources Management’s personnel in a manner that will allow us to carry on our business in the same manner in which it was carried on by our predecessor.
 
Quantum Resources Management will provide substantially similar services to the Fund, one of our affiliates. Should Quantum Energy Partners form other funds, Quantum Resources Management may enter into similar arrangements with those new funds. Because Quantum Resources Management will be providing services to us that are substantially similar to those provided to the Fund and, potentially, other funds, Quantum Resources Management may not have sufficient human, technical and other resources to provide those services at a level that Quantum Resources Management would be able to provide to us if it did not provide those similar services to the Fund and those other funds. The assets that the Fund will retain with respect to which Quantum Resources Management provides such services had pro forma average net production of approximately 13,132 Boe/d for the nine months ended September 30, 2010. Additionally, Quantum Resources Management may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of the Fund or other funds. There is no requirement that Quantum Resources Management favor us over the Fund or other funds in providing its services. If the employees of Quantum Resources Management and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.


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We Have Material Weaknesses in Our Internal Control Over Financial Reporting. If One or More Material Weaknesses Persist or If We Fail to Establish and Maintain Effective Internal Control Over Financial Reporting, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected.
 
Prior to the completion of this offering, our predecessor has been a private company with limited accounting personnel and other supervisory resources to adequately execute its accounting processes and address our internal control over financial reporting. This lack of adequate accounting resources contributed to audit adjustments to the financial statements for the year ended December 31, 2009 and review adjustments for the six months ended June 30, 2010. In connection with our predecessor’s audit for the year ended December 31, 2009, our predecessor’s independent registered accounting firm identified and communicated to our predecessor material weaknesses, including a material weakness related to maintaining an effective control environment in that the design and operation of its controls have not consistently resulted in effective review and supervision.
 
The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our predecessor’s financial statements. This material weakness contributed to multiple audit and review adjustments and the following individual material weaknesses:
 
  •  Our predecessor did not design and operate effective controls to ensure the completeness and accuracy of the inputs with respect to the full cost ceiling impairment test and depreciation, depletion and amortization calculations.
 
  •  Our predecessor did not design and operate effective controls over the calculation and review of the non-performance risk adjustment related to the valuation of derivative contracts.
 
  •  For the six months ended June 30, 2010, our predecessor did not design and operate effective controls to ensure that all revenue was recognized and expenses recorded in connection with its newly acquired Denbury Assets.
 
During the first six months of 2010, our predecessor also did not maintain effective controls over completeness and accuracy of the inputs with respect to depreciation, depletion and amortization calculations or the non-performance risk adjustment related to estimates of fair value of derivative contracts.
 
After the closing of this offering, our management team and financial reporting oversight personnel will be those of our predecessor, and thus, we will face the same control deficiencies described above.
 
In response, we have begun the process of evaluating our internal control over financial reporting, although we are in the early phases of our review and may not complete our review until after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weaknesses previously identified. Each of the material weaknesses described above could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim consolidated financial statements that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses described above or avoid potential future material weaknesses.
 
The Management Incentive Fee We Will Pay to Our General Partner May Increase in Situations Where There Is No Corresponding Increase in Distributions to Our Common Unitholders.
 
Under our partnership agreement, for each quarter for which we have paid cash distributions that equaled or exceeded the Target Distribution, our general partner will be entitled to a quarterly


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management incentive fee, payable in cash, equal to 0.25% of the management incentive fee base, which will be an amount equal to the sum of:
 
  •  the future net revenue of our estimated proved oil and natural gas reserves, discounted to present value at 10% per annum and calculated based on SEC methodology, adjusted for our commodity derivative contracts; and
 
  •  the fair market value of our assets, other than our estimated oil and natural gas reserves and our commodity derivative contracts, that principally produce qualifying income for federal income tax purposes, at such value as may be determined by the board of directors of our general partner and approved by the conflicts committee of our general partner’s board of directors.
 
The maximum amount of the management incentive fee payable to our general partner in respect of any quarter is not dependent upon the amount of distributions to unitholders increasing beyond 115% of our minimum quarterly distribution. As a result, the management incentive fee may increase as the value of our oil and natural gas reserves and other assets increase even though distributions to unitholders may remain the same or even decrease. In addition, our general partner may have a conflict in deciding whether to reserve cash to invest in developing our oil and natural gas properties to increase the value of our assets (which would increase the management incentive fee) or deciding to make cash available for distributions to our unitholders. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — General Partner Interest and Management Incentive Fee” on page 100 and “— General Partner’s Right to Convert Management Incentive Fee into Class B Units” on page 101.
 
If Our General Partner Converts a Portion of Its Management Incentive Fee in Respect of a Quarter Into Class B Units, It Will Be Entitled To Receive Pro Rata Distributions on Those Class B Units When and If We Pay Distributions on Our Common Units, Even If the Value of Our Properties Declines and a Lower Management Incentive Fee Is Owed in Future Quarters.
 
From and after the end of the subordination period and subject to certain exceptions, our general partner will have the continuing right, at any time when it has received all or any portion of the quarterly management incentive fee for three consecutive calendar quarters and shall be entitled to receive all or a portion of the management incentive fee for a fourth consecutive quarter, to convert into Class B units up to 80% of the management incentive fee for the fourth quarter in lieu of receiving a cash payment for each portion of the management incentive fee. The Class B units will have the same rights, preferences and privileges of our common units and will be entitled to the same cash distributions per unit as our common units, except in liquidation where distributions are made in accordance with the respective capital accounts of the units, and will be convertible into an equal number of common units at the election of the holder. As a result, if the value of our properties declines in periods subsequent to the conversion, our general partner may receive higher cash distributions with respect to Class B units than it otherwise would have received in respect of the management incentive fee it converted. The Class B units issued to our general partner upon conversion of the management incentive fee will not be subject to forfeiture should the value of our assets decline in subsequent periods. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — General Partner Interest and Management Incentive Fee” on page 100 and “— General Partner’s Right to Convert Management Incentive Fee into Class B Units” on page 101.
 
Many of the Directors and Officers Who Have Responsibility for Our Management Have Significant Duties with, and Will Spend Significant Time Serving, Entities That Compete with Us in Seeking Acquisitions and Business Opportunities and, Accordingly, May Have Conflicts of Interest in Allocating Time or Pursuing Business Opportunities.
 
To maintain and increase our levels of production, we will need to acquire oil and natural gas properties. Several of the officers and directors of our general partner, who are responsible for managing our operations and acquisition activities, hold similar positions with other entities that are in the


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business of identifying and acquiring oil and natural gas properties. For example, our general partner will be owned 50% by an entity controlled by Mr. Smith, the Chief Executive Officer and a director of our general partner and Chief Executive Officer and a director of Quantum Resources Management, and Mr. Campbell, the President and Chief Operating Officer and a director of our general partner and President, Chief Operating Officer and a director of Quantum Resources Management. Mr. Smith and Mr. Campbell manage the Fund, and the Fund is also in the business of acquiring oil and natural gas properties. In addition, our general partner will be owned 50% by an entity controlled by Mr. Neugebauer and Mr. VanLoh, who are directors of our general partner and also managing partners of Quantum Energy Partners. Mr. Burgher, the Chief Financial Officer of our general partner, serves on the board of a Quantum Energy Partners portfolio company. Quantum Energy Partners is in the business of investing in oil and natural gas companies with independent management, and those companies also seek to acquire oil and natural gas properties. Mr. Neugebauer and Mr. VanLoh are also directors of several oil and natural gas producing entities that are in the business of acquiring oil and natural gas properties. Mr. Wolf, the Chairman of the board of directors of our general partner, is also the chief executive officer and a director of the general partner of the Fund and is on the board of directors of other companies who also seek to acquire oil and natural gas properties. After the closing of this offering, several officers of our general partner will continue to devote significant time to the other businesses, including businesses to which Quantum Resources Management provides management and administrative services. The existing positions held by these directors and officers may give rise to fiduciary duties that are in conflict with fiduciary duties they owe to us. We cannot assure our unitholders that these conflicts will be resolved in our favor. As officers and directors of our general partner these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present them to us. For a complete discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, see the sections entitled “Business and Properties — Our Principal Business Relationships” on page 146 and “Conflicts of Interest and Fiduciary Duties” on page 193.
 
Our Right of First Offer to Purchase Certain of the Fund’s Producing Properties and Right to Participate in Acquisition Opportunities with the Fund Are Subject to Risks and Uncertainty, and Thus May Not Enhance Our Ability to Grow Our Business.
 
Under the terms of our omnibus agreement, the Fund will commit to offer us the first opportunity to purchase properties that it may offer for sale, so long as the properties consist of at least 70% proved developed producing reserves. Additionally, the Fund will agree to offer us the first option to acquire at least 25% of each acquisition available to it, so long as at least 70% of the allocated value is attributable to proved developed producing reserves. The consummation and timing of any future transactions pursuant to either such right with respect to any particular acquisition opportunity will depend upon, among other things, our ability to negotiate definitive agreements with respect to such opportunities and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future transactions pursuant to these rights. Additionally, the Fund is under no obligation to accept any offer made by us to purchase properties that it may offer for sale. Furthermore, for a variety of reasons, we may decide not to exercise these rights when they become available, and our decision will not be subject to unitholder approval. Additionally, while the general partner of the Fund will agree that, if it or its affiliates establish another fund to acquire oil and natural gas properties within two years of the closing of this offering, it will cause such fund to provide us with a similar right to participate in such fund’s acquisition opportunities, the general partner of the Fund and its affiliates are under no obligation to create an additional fund, and even if an additional fund is created, our ability to consummate acquisitions in partnership with such fund will be subject to each of the risks outlined above. The contractual obligations under the omnibus agreement automatically


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terminate five years following the closing of this offering. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement” on page 188.
 
After December 31, 2012, We Will Have to Reimburse Quantum Resources Management for All Allocable Expenses It Incurs on Our Behalf in Its Performance Under the Services Agreement As Opposed to Paying the Fixed Services Fee in Effect Until December 31, 2012. Our Actual Allocated Expenses After December 31, 2012 May Be Substantially More Than the Administrative Services Fee We Pay Under the Fixed Rate Currently in Effect, Which Could Materially Reduce the Cash Available for Distribution to Our Unitholders at That Time.
 
Under the services agreement that our general partner will enter into in connection with the closing of this offering, from the closing of this offering through December 31, 2012, Quantum Resources Management will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. For the nine months ended September 30, 2010, 3.5% of our unaudited pro forma Adjusted EBITDA, calculated prior to the payment of the fee, would have been approximately $2.0 million. For the twelve months ending December 31, 2011 3.5% of such estimated Adjusted EBITDA, calculated prior to the payment of the fee, would be approximately $3.1 million, assuming we generate estimated Adjusted EBITDA as set forth in “Cash Distribution Policy and Restrictions on Distributions — Estimated Adjusted EBITDA for the Twelve Months Ending December 31, 2011” beginning on page 77. After December 31, 2012, in lieu of the quarterly administrative services fee, our general partner will reimburse Quantum Resources Management, on a quarterly basis, for the allocable expenses it incurs in its performance under the services agreement, and we will reimburse our general partner for such payments it makes to Quantum Resources Management. Our actual allocated expenses after December 31, 2012 may be substantially more than the administrative services fee we pay under the fixed rate currently in effect, which could materially reduce the cash available for distribution to our unitholders at that time. For a detailed description of the administrative services fee, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement” on page 188.
 
Units Held by Persons Who Our General Partner Determines Are Not Eligible Holders Will Be Subject to Redemption.
 
To comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means:
 
  •  a citizen of the United States;
 
  •  a corporation organized under the laws of the United States or of any state thereof;
 
  •  a public body, including a municipality; or
 
  •  an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.
 
Onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder, will run the risk of having their common units redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of the Common Units — Transfer of Common Units” on page 204 and “The Partnership Agreement — Non-Eligible Holders; Redemption” on page 217.


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Our Unitholders Have Limited Voting Rights and Are Not Entitled to Elect Our General Partner or Its Board of Directors. Affiliates of the Fund and Quantum Energy Partners, as the Owners of Our General Partner, Will Have the Power to Appoint and Remove Our General Partner’s Directors.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner will be chosen by affiliates of the Fund and Quantum Energy Partners. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
 
Our general partner will have control over all decisions related to our operations. Since, upon consummation of this offering, affiliates of the Fund and Quantum Energy Partners will own our general partner and, through ownership of the general partner of the Fund, will control an aggregate of approximately 47.5% of our outstanding common units and all of our subordinated units, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by the Fund and its affiliates) after the subordination period has ended. Assuming we do not issue any additional common units and the Fund does not transfer its common units, the Fund will have the ability to amend our partnership agreement, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholder once the subordination period ends. Furthermore, the goals and objectives of the affiliates of the Fund and Quantum Energy Partners that hold our common units and our general partner relating to us may not be consistent with those of a majority of the other unitholders. Please read “— Our General Partner and Its Affiliates Own a Controlling Interest in Us and Will Have Conflicts of Interest and Limited Fiduciary Duties, Which May Permit Them to Favor Their Own Interests to the Detriment of Our Unitholders” on page 48.
 
Our General Partner Will Be Required to Deduct Estimated Maintenance Capital Expenditures from Our Operating Surplus, Which May Result In Less Cash Available for Distribution to Unitholders from Operating Surplus Than if Actual Maintenance Capital Expenditures Were Deducted.
 
Maintenance capital expenditures are those capital expenditures required to maintain our long-term asset base, including expenditures to replace our oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation. In addition, the ability of our general partner to receive a management incentive fee is based on the amount of cash distributed to our unitholders


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from operating surplus, which in turn is partially dependent upon its determination of our estimated maintenance capital expenditures. If estimated maintenance capital expenditures are lower than actual maintenance capital expenditures, then our general partner may be entitled to the management incentive fee at times when cash distributions to our unitholders would not have come from operating surplus if operating surplus was reduced by actual maintenance capital expenditures.
 
Our Partnership Agreement Limits Our General Partner’s Fiduciary Duties to Unitholders and Restricts the Remedies Available to Unitholders for Actions Taken by Our General Partner That Might Otherwise Constitute Breaches of Fiduciary Duty.
 
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
 
  •  permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement;
 
  •  provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith;
 
  •  generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
 
  •  provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
 
  •  provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
 
By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” beginning on page 201.


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Even If Our Unitholders Are Dissatisfied, They Cannot Remove Our General Partner Without Its Consent.
 
The public unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove our general partner. Upon consummation of this offering, affiliates of the Fund and Quantum Energy Partners will own our general partner and, through ownership of the general partner of the Fund, will control an aggregate of approximately 47.5% of our outstanding common units and all of our subordinated units.
 
Our General Partner’s Interest in Us, Including Its Right to Receive the Management Incentive Fee, and the Control of Our General Partner May Be Transferred to a Third Party Without Unitholder Consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner, who are affiliates of both the Fund and Quantum Energy Partners, from transferring all or a portion of their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and officers. Additionally, our general partner or its owners may assign the right to receive the management incentive fee and to convert such management incentive fee into Class B units to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the holders. To the extent the owners of our general partner have interests aligned with those of our unitholders to grow our business and increase our distributions, any assignment of the right to receive the management incentive fee and to convert such management incentive fee into Class B units to a third party would diminish the incentives of the owners of our general partner to pursue a business strategy that favors us.
 
We May Not Make Cash Distributions During Periods When We Record Net Income.
 
The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.
 
We May Issue an Unlimited Number of Additional Units, Including Units That Are Senior to the Common Units, Without Unitholder Approval, Which Would Dilute Unitholders’ Ownership Interests.
 
Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
 
  •  our unitholders’ proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  the ratio of taxable income to distributions may increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of our common units may decline.


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Our Partnership Agreement Restricts the Limited Voting Rights of Unitholders, Other Than Our General Partner and Its Affiliates, Owning 20% or More of Our Common Units, Which May Limit the Ability of Significant Unitholders to Influence the Manner or Direction of Management.
 
Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.
 
Once Our Common Units Are Publicly Traded, the Fund May Sell Common Units in the Public Markets, Which Sales Could Have an Adverse Impact on the Trading Price of the Common Units.
 
After the sale of the common units offered hereby, the Fund will control an aggregate of           of our outstanding common units and all of our subordinated units, which convert into common units at the end of the subordination period. Additionally, from and after the end of the subordination period, and subject to certain limitations, our general partner will have the continuing right, from time to time, to convert up to 80% of its management incentive fee into Class B units, which will be convertible into common units at the holder’s election. Once our common units are publicly traded, the sale of these units, including common units issued upon the conversion of the subordinated units or the management incentive fee, in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.
 
Our General Partner Has a Call Right That May Require Common Unitholders to Sell Their Common Units at an Undesirable Time or Price.
 
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. Upon consummation of this offering, the Fund will control an aggregate of approximately 47.5% of our outstanding common units and all of our subordinated units. For additional information about this call right, please read “The Partnership Agreement — Limited Call Right” on page 216.
 
If We Distribute Cash from Capital Surplus, Which is Analogous to a Return of Capital, Our Minimum Quarterly Distribution Will Be Reduced Proportionately, and the Target Distribution Relating to Our General Partner’s Management Incentive Fee Will Be Proportionately Decreased.
 
Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes and any payments in respect of the management incentive fee, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in the glossary and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders


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and our general partner in proportion to their percentage interests in us, or 99.9% to our unitholders and 0.1% to our general partner, and will result in a decrease in our minimum quarterly distribution and a lower Target Distribution used in calculating the management incentive fee paid to our general partner, which may have the effect of increasing the likelihood that our general partner would earn the management incentive fee in future periods. For a more detailed description of operating surplus, capital surplus and the effect of distributions from capital surplus, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee” beginning on page 93.
 
Our Unitholders’ Liability May Not Be Limited If a Court Finds That Unitholder Action Constitutes Control of Our Business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:
 
  •  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
 
Please read “The Partnership Agreement — Limited Liability” on page 209 for a discussion of the implications of the limitations of liability on a unitholder.
 
Our Unitholders May Have Liability to Repay Distributions.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.
 
Our Unitholders May Have Limited Liquidity for Their Common Units, a Trading Market May Not Develop for the Common Units and Our Unitholders May Not Be Able to Resell Their Common Units at the Initial Public Offering Price.
 
Prior to this offering, there has been no public market for the common units. After this offering, there will be publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, a lack of liquidity would likely result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.


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If Our Common Unit Price Declines After the Initial Public Offering, Our Unitholders Could Lose a Significant Part of Their Investment.
 
The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
 
  •  changes in commodity prices;
 
  •  changes in securities analysts’ recommendations and their estimates of our financial performance;
 
  •  public reaction to our press releases, announcements and filings with the SEC;
 
  •  fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;
 
  •  changes in market valuations of similar companies;
 
  •  departures of key personnel;
 
  •  commencement of or involvement in litigation;
 
  •  variations in our quarterly results of operations or those of other oil and natural gas companies;
 
  •  variations in the amount of our quarterly cash distributions to our unitholders;
 
  •  future issuances and sales of our common units; and
 
  •  changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.
 
In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
 
Because We Are a Relatively Small Company, the Requirements of Being a Public Company, Including Compliance with the Reporting Requirements of the Exchange Act and the Requirements of the Sarbanes-Oxley Act May Strain Our Resources, Increase Our Costs and Distract Management, and We May Be Unable to Comply with These Requirements in a Timely or Cost-Effective Manner.
 
As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our cash costs after December 31, 2012, because our general partner’s services agreement with Quantum Resources Management provides that our general partner must begin reimbursing Quantum Resources Management for the expenses it allocates to us, which amounts we will then reimburse to our general partner. We will need to:
 
  •  institute a more comprehensive compliance function;
 
  •  design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;


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  •  comply with rules promulgated by the NYSE;
 
  •  prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
 
  •  establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;
 
  •  involve and retain to a greater degree outside counsel and accountants in the above activities; and
 
  •  establish an investor relations function.
 
In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for our general partner to attract and retain qualified executive officers and qualified members to serve on its board of directors, particularly the Audit Committee of the board of directors.
 
We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, including information technology, implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.
 
Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future. Any failure to remediate material weaknesses or significant deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanctions or investigations by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.
 
Our Unitholders Will Experience Immediate and Substantial Dilution of $15.56 per Unit.
 
The initial offering price of $20.00 per common unit exceeds our pro forma net tangible book value after this offering of $4.44 per common unit. Based on the initial offering price of $20.00 per common unit, our unitholders will incur immediate and substantial dilution of $15.56 per common unit. This dilution will occur primarily because the assets contributed by affiliates of our general partner are recorded, in accordance with GAAP at their historical cost, and not their fair value. The impact of such dilution would be magnified upon any conversion of the management incentive fee into Class B units. Please read “Dilution” on page 68.
 
Tax Risks to Unitholders
 
In addition to reading the following risk factors, prospective unitholders should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our units.


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Our Tax Treatment Depends on Our Status As a Partnership for Federal Income Tax Purposes. If the IRS Were to Treat Us As a Corporation, Then Our Cash Available for Distribution to Our Unitholders Would Be Substantially Reduced.
 
The anticipated after-tax economic benefit of an investment in the units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
 
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based on our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
 
If We Were Subjected to a Material Amount of Additional Entity-Level Taxation By Individual States, It Would Reduce Our Cash Available for Distribution to Our Unitholders.
 
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the Target Distribution may be adjusted to reflect the impact of that law on us.
 
The Tax Treatment of Publicly Traded Partnerships or an Investment in Our Units Could Be Subject to Potential Legislative, Judicial or Administrative Changes and Differing Interpretations, Possibly on a Retroactive Basis.
 
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.
 
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and the Target Distribution may be adjusted to reflect the impact of that law on us.


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Certain U.S. Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production May Be Eliminated As a Result of Future Legislation.
 
President Obama’s Proposed Fiscal Year 2011 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Each of these changes is proposed to be effective for taxable years beginning, or in the case of costs described in (ii) and (iv), costs paid or incurred, after December 31, 2010. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.
 
If the IRS Contests Any of the Federal Income Tax Positions We Take, the Market for Our Units May Be Adversely Affected, and the Costs of Any IRS Contest Will Reduce Our Cash Available for Distribution to Our Unitholders.
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
Our Unitholders Will Be Required to Pay Taxes on Their Share of Our Income Even If They Do Not Receive Any Cash Distributions from Us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
 
Tax Gain or Loss on the Disposition of Our Units Could Be More or Less Than Expected.
 
If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Because distributions in excess of their allocable share of our total net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion and IDC recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale. Please read “Material Tax Consequences — Disposition of Units — Recognition of Gain or Loss” on page 235.


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Tax-Exempt Entities and Non-U.S. Persons Face Unique Tax Issues from Owning Our Units That May Result in Adverse Tax Consequences to Them.
 
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units.
 
We Will Treat Each Purchaser of Units As Having the Same Tax Benefits Without Regard to the Units Purchased. The IRS May Challenge This Treatment, Which Could Adversely Affect the Value of the Units.
 
Because we cannot match transferors and transferees of units and because of other reasons, we will adopt depletion, 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 from the sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” on page 229 for a further discussion of the effect of the depletion, depreciation and amortization positions we will adopt.
 
We Will Prorate Our Items of Income, Gain, Loss and Deduction Between Transferors and Transferees of Our Units Each Month Based Upon the Ownership of Our Units on the First Day of Each Month, Instead of on the Basis of the Date a Particular Unit Is Transferred. The IRS May Challenge This Treatment, Which Could Change the Allocation of Items of Income, Gain, Loss and Deduction Among Our Unitholders.
 
We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Vinson & Elkins L.L.P. has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Tax Consequences — Disposition of Units — Allocations Between Transferors and Transferees” on page 236.
 
A Unitholder Whose Units Are Loaned to a “Short Seller” to Cover a Short Sale of Units May Be Considered As Having Disposed of Those Units. If So, He Would No Longer Be Treated for Tax Purposes As a Partner with Respect to Those Units During the Period of the Loan and May Recognize Gain or Loss From the Disposition.
 
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by


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the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where units are loaned to a short seller to cover a short sale of units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
 
The Sale or Exchange of 50% or More of Our Capital and Profits Interests During Any Twelve-Month Period Will Result In the Termination of Our Partnership for Federal Income Tax Purposes.
 
We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs. Please read “Material Tax Consequences — Disposition of Units — Constructive Termination” on page 236 for a discussion of the consequences of our termination for federal income tax purposes.
 
As a Result of Investing In Our Units, Our Unitholders May Become Subject to State and Local Taxes and Return Filing Requirements in Jurisdictions Where We Operate or Own or Acquire Property.
 
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future even if such unitholders do not live in those jurisdictions. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We initially will own property and conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property or conduct business in other states or foreign countries in the future. It is a unitholder’s responsibility to file all U.S. federal, state and local tax returns. Vinson & Elkins L.L.P. has not rendered an opinion on the state or local tax consequences of an investment in our units.


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USE OF PROCEEDS
 
We expect to receive net proceeds from the issuance and sale of the 15,000,000 common units offered hereby of approximately $275.0 million, after deducting underwriting discounts, structuring fees and expenses. We intend to use all of the net proceeds from this offering, together with borrowings of approximately $225 million under our new credit facility, to make a cash distribution to the Fund of approximately $300 million and to repay in full approximately $200 million of the Fund’s debt that we will assume at closing.
 
The approximately $200 million of the Fund’s debt that we will assume and repay in full at closing was incurred in connection with the Denbury Acquisition under two credit facilities of the Fund that are secured by mortgages on oil and natural gas properties, including the Partnership Properties. As of September 30, 2010, the interest rate on each of the Fund’s credit facilities that burden the Partnership Properties was 3.02%, and each credit facility matures on May 14, 2014.
 
The following table illustrates our use of the proceeds from this offering and our borrowings under our new credit facility.
 
                     
Sources of Cash (in millions)     Uses of Cash (in millions)      
 
Gross proceeds from this offering
  $ 300.0     Distribution to the Fund   $ 300.0 (1)
Borrowings under new credit facility
  $ 225.0     Repayment of debt assumed from the Fund   $ 200.0  
            Underwriting discounts, structuring fees and other offering expenses payable by us   $ 25.0  
Total
  $ 525.0     Total   $ 525.0  
                     
 
 
(1) If the underwriters exercise their option to purchase additional common units in full, the total distribution to the Fund would be approximately $342.0 million.
 
If the underwriters do not exercise their option to purchase up to an additional 2,250,000 common units, we will issue the additional 2,250,000 common units to the Fund at the expiration of this offering. The share numbers presented in this prospectus assume that the underwriters do not exercise their option to purchase the additional common units. To the extent the underwriters do exercise their option to purchase the additional common units, the number of common units issued to the Fund (as presented in this prospectus) will decrease by, and the number of common units issued to the public (as presented in this prospectus) will increase by, the aggregate number of common units purchased by the underwriters pursuant to such exercise. The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be paid to the Fund. This payment of net proceeds or issuance of additional units is intended to represent a portion of the consideration paid to the Fund for its contribution of the Partnership Properties to us.


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CAPITALIZATION
 
The following table shows:
 
  •  the historical capitalization of our predecessor as of September 30, 2010; and
 
  •  our pro forma capitalization as of September 30, 2010, adjusted to reflect the issuance and sale of common units to the public at an initial offering price of $20.00 per common unit, the other formation transactions described under “Prospectus Summary — Formation Transactions and Partnership Structure” on page 8 and the application of the net proceeds from this offering as described under “Use of Proceeds” on page 66.
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 112. For a description of the pro forma adjustments, please read our Unaudited Pro Forma Condensed Financial Statements.
 
                 
    As of September 30, 2010  
    Our
       
    Predecessor
    Pro Forma
 
    Historical     QR Energy, LP  
    (in thousands)  
 
Long-term debt(1)
  $ 547,668     $ 225,000  
Noncontrolling interest in consolidated subsidiaries
    482,552        
Partners’ capital/net equity:
               
Predecessor partners’ capital
    16,795        
Common units held by purchasers in this offering
          66,571  
Common units held by the Fund
          60,072  
Subordinated units held by the Fund
          31,700  
General partner interest
          159  
                 
Total partners’ capital/net equity
    16,795       158,502  
                 
Total capitalization
  $ 1,047,015     $ 383,502  
                 
 
 
(1) We intend to enter into a $750 million credit facility, approximately $75.0 million of which will be available for borrowing upon the completion of the transactions described under “Prospectus Summary — Formation Transactions and Partnership Structure” on page 8.


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DILUTION
 
Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per unit after this offering. Net tangible book value is our total tangible assets less total liabilities. On a pro forma as adjusted basis as of September 30, 2010, after giving effect to the transactions described under “Prospectus Summary — Formation Transactions and Partnership Structure” on page 8, including this offering of common units and the application of the related net proceeds, our net tangible book value was $158.5 million, or $4.44 per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:
 
                 
Initial offering price per common unit
          $ 20.00  
Pro forma as adjusted net tangible book value per unit before this offering(1)
  $ 8.71          
Decrease in net tangible book value per unit attributable to purchasers in this offering
    (4.27 )        
                 
Less: Pro forma as adjusted net tangible book value per unit after this offering(2)
            4.44  
                 
Immediate dilution in net tangible book value per unit to purchasers in this offering(3)
          $ 15.56  
                 
 
 
(1) Determined by dividing the pro forma net tangible book value of our net assets immediately prior to the offering by the number of units (13,547,737 common units, 7,145,866 subordinated units to be issued to the Fund as partial consideration for their contribution of the Partnership Properties to us and the issuance of 35,729 general partner units) to be issued to the Fund and our general partner.
 
(2) Determined by dividing our pro forma as adjusted net tangible book value, after giving effect to the application of the net proceeds of this offering, by the total number of units to be outstanding after this offering (28,547,737 common units, 7,145,866 subordinated units and 35,729 general partner units).
 
(3) Because the total number of units outstanding following the consummation of this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the underwriters’ option to purchase additional common units.


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The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates, including the Fund, in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:
 
                                 
    Units Acquired     Total Consideration  
    Number     Percent     $     Percent  
                (in millions)        
 
General partner and its affiliates(1)(2)
    20,729,332       58 %   $ 180.5       40 %
Purchasers in this offering(3)
    15,000,000       42 %     275.0       60 %
                                 
Total
    35,729,332       100 %   $ 455.5       100 %
                                 
 
 
(1) Upon the consummation of the transactions contemplated by this prospectus, and assuming the underwriters do not exercise their option to purchase additional common units, our general partner, its owners and their affiliates will own 13,547,737 common units, 7,145,866 subordinated units and 35,729 general partner units.
 
(2) The assets contributed by affiliates of our general partner were recorded at historical cost in accordance with GAAP. Total consideration provided by affiliates of our general partner is equal to the net tangible book value of such assets as of September 30, 2010.
 
(3) Total consideration is after deducting underwriting discounts and estimated offering expenses.


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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
 
You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “— Estimated Adjusted EBITDA for the Twelve Months Ending December 31, 2011” on page 77 below. In addition, you should read “Forward-Looking Statements” beginning on page 250 and “Risk Factors” beginning on page 29 for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.
 
For additional information regarding our historical and unaudited pro forma operating results, you should refer to the unaudited historical consolidated financial statements of our predecessor for the nine months ended September 30, 2010, the audited historical consolidated financial statements of our predecessor for the period from January 1, 2007 to December 31, 2009, and our unaudited pro forma condensed financial statements for the year ended December 31, 2009 and the nine months ended September 30, 2010 included elsewhere in this prospectus.
 
General
 
Rationale for Our Cash Distribution Policy
 
Our partnership agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. We intend to fund a portion of our capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Also, because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case if we were subject to federal income tax.
 
Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
 
There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:
 
  •  Our cash distribution policy may be subject to restrictions on distributions under our new credit facility or other debt agreements that we may enter into in the future. Specifically, we anticipate that the agreement related to our new credit facility will contain material financial tests and covenants that we must satisfy. These financial ratios and covenants are described under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — New Credit Facility” on page 123. Should we be unable to satisfy these restrictions, or if a default occurs under our new credit facility, we would be prohibited from making cash distributions to our unitholders notwithstanding our stated cash distribution policy.
 
  •  Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions to our unitholders from levels we currently anticipate under our stated distribution policy. Any determination to establish or increase reserves made by our general partner in good faith will be binding on the unitholders. We intend to reserve a portion of our cash generated from operations to fund our exploitation and development capital expenditures. Over a longer period of time, if our general partner does


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  not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our asset base, we will be unable to pay the minimum quarterly distribution from cash generated from operations and would therefore expect to reduce our distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions may be considered a return of part of our unitholders’ investment in us as opposed to a return on our unitholders’ investment.
 
  •  Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units that are held by the Fund and its affiliates) after the subordination period has ended. Upon consummation of this offering, affiliates of the Fund and Quantum Energy Partners will own our general partner and, through ownership of the general partner of the Fund, will control the voting of an aggregate of approximately 47.5% of our outstanding common units and all of our subordinated units, and, assuming we do not issue any additional common units and the Fund does not transfer its common units, the Fund will have the ability to amend our partnership agreement without the approval of any other unitholder once the subordination period ends.
 
  •  Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement, our new credit facility and any other debt agreements we may enter into in the future.
 
  •  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.
 
  •  We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including reductions in commodity prices, reductions in our oil and natural gas production, increases in our general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs. For a discussion of additional factors that may affect our ability to pay distributions, please read “Risk Factors” beginning on page 29.
 
  •  If and to the extent our cash available for distribution materially declines, we may reduce our quarterly distribution in order to service or repay our debt or fund growth capital expenditures.
 
  •  All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the cumulative operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components that represent non-operating sources of cash, including a $40 million cash basket and working capital borrowings. Consequently, it is possible that distributions from operating surplus may represent a return of capital. For example, the $40 million cash basket would allow us to distribute as operating surplus cash proceeds we receive from non-operating sources, such as assets sales, issuances of securities and long-term borrowings, which would represent a return of capital. Distributions representing a return of capital could result in a corresponding decrease in our asset base. Additionally, any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is similar to a return of capital. Distributions from capital surplus could result in a corresponding decrease in our asset


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  base. We do not anticipate that we will make any distributions from capital surplus. Please read “Risk Factors — Risks Inherent in an Investment in Us — If We Distribute Cash from Capital Surplus, Which is Analogous to a Return of Capital, Our Minimum Quarterly Distribution Will Be Reduced Proportionately, and the Target Distribution Relating to Our General Partner’s Management Incentive Fee Will Be Proportionately Decreased” on page 58, and “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — Operating Surplus and Capital Surplus” on page 94 and “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — Distributions from Capital Surplus — Effect of a Distribution from Capital Surplus” on page 105.
 
Our Ability to Grow Depends on Our Ability to Access External Growth Capital
 
Our partnership agreement requires us to distribute all of our available cash to unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund our growth capital expenditures. To the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand their ongoing operations. To the extent we issue additional units in connection with any growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our quarterly per unit distribution level. There are no limitations in our partnership agreement or our new credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
 
Our Minimum Quarterly Distribution
 
Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $0.4125 per unit per whole quarter, or $1.65 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending December 31, 2010. This equates to an aggregate cash distribution of approximately $14.7 million per quarter or $59.0 million per year, in each case based on the number of common units, subordinated units and general partner units outstanding immediately after completion of this offering. The number of outstanding common, subordinated and general partner units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering. To the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remaining common units subject to the option, if any, will be issued to the Fund at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Our ability to make cash distributions at the minimum quarterly distribution will be subject to the factors described above under the caption “— General — Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy” on page 70.
 
As of the date of this offering, our general partner will be entitled to 0.1% of all distributions of available cash that we make prior to our liquidation. Our general partner’s initial 0.1% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest.


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The table below sets forth the number of outstanding common, subordinated and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution of $0.4125 per unit per quarter, or $1.65 per unit on an annualized basis. These amounts do not reflect any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering or Class B units that may be issued in the future to our general partner pursuant to the conversion of the management incentive fee.
 
                         
    Number of
    Minimum Quarterly Distribution  
    Units     One Quarter     Four Quarters  
 
Common units held by purchasers in this offering(1)(2)
    15,000,000     $ 6,187,500     $ 24,750,000  
Common units held by the Fund and its affiliates(1)(2)
    13,547,737       5,588,442       22,353,766  
Subordinated units
    7,145,866       2,947,670       11,790,679  
General partner units
    35,729       14,738       58,953  
                         
Total
    35,729,332     $ 14,738,350     $ 58,953,398  
                         
 
 
(1) Assumes the underwriters do not exercise their option to purchase additional common units. If the underwriters do not exercise their option to purchase up to an additional 2,250,000 common units, we will issue the additional 2,250,000 common units to the Fund at the expiration of the option. To the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder, if any, will be issued to the Fund at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.
 
(2) Does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.
 
If the minimum quarterly distribution on our common units is not paid with respect to any quarter, the common unitholders and Class B unitholders, if any, will not be entitled to receive such payments in the future except that, during the subordination period, to the extent we distribute cash in any future quarter in excess of the amount necessary to make cash distributions at the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any of these arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — Subordination Period” on page 98.
 
We do not have a legal obligation to pay the minimum quarterly distribution or distributions at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of expenses and the amount of reserves our general partner determines is necessary or appropriate to provide for the prudent conduct of our business (including payments to our general partner for reimbursement of expenses it incurs on our behalf and payment of any portion of the management incentive fee to the extent it will become payable in connection with the payment of the distribution), to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee — Distributions of Available Cash — Definition of Available Cash” on page 93.


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Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests.
 
Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuation based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement, including provisions contained therein requiring us to make cash distributions, may be amended by a vote of the holders of a majority of our common units. At the closing of this offering, affiliates of the Fund and Quantum Energy Partners will own our general partner and, through ownership of the general partner of the Fund, will control an aggregate of approximately 47.5% of our outstanding common units and all of our subordinated units. The owners of our general partner also control the Fund, and, assuming we do not issue any additional common units and the Fund does not transfer its common units, they will have the ability to amend our partnership agreement without the approval of any other unitholders once the subordination period ends.
 
We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. For our initial quarterly distribution, we will adjust the quarterly distribution for the period from the closing of this offering through December 31, 2010 based on the actual length of the period. We expect to pay this initial quarterly cash distribution on or before February 15, 2011.
 
In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $0.4125 per unit each quarter for the four quarters of the fiscal year ending December 31, 2011. In those sections, we present two tables, consisting of:
 
  •  “Unaudited Pro Forma Available Cash,” in which we present the amount of cash we would have had available for distribution to our unitholders and our general partner for the year ended December 31, 2009 and the twelve months ended September 30, 2010, based on our unaudited pro forma financial statements. Our calculation of unaudited pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had the transactions contemplated in this prospectus occurred in an earlier period.
 
  •  “Estimated Cash Available for Distribution,” in which we demonstrate our ability to generate the minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the full minimum quarterly distribution on all the outstanding units, including our general partner units, for the twelve months ending December 31, 2011.
 
Unaudited Pro Forma Available Cash for the Year Ended December 31, 2009 and
the Twelve Months Ended September 30, 2010
 
If we had completed the formation transactions contemplated in this prospectus and the acquisition of all of the Partnership Properties on January 1, 2009, our unaudited pro forma available cash for the year ended December 31, 2009 would have been approximately $47.7 million. This amount would not have been sufficient to make a cash distribution for the year ended December 31, 2009 at the


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minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units and subordinated units. Specifically, this amount would have been sufficient to allow us to pay the full minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units and a cash distribution of $0.0190 per unit per quarter (or $0.08 per unit on an annualized basis) on all of the subordinated units, or only approximately 4.6% of the minimum quarterly distribution. The number of outstanding common and subordinated units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.
 
If we had completed the transactions contemplated in this prospectus and the acquisition of all of our properties on October 1, 2009, our unaudited pro forma available cash for the twelve months ended September 30, 2010 would have been approximately $51.3 million. This amount would not have been sufficient to make a cash distribution for the twelve months ended September 30, 2010 at the minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units and subordinated units. Specifically, this amount would have been sufficient to allow us to pay the full minimum quarterly distribution of $0.4125 per unit per quarter (or $1.65 per unit on an annualized basis) on all of the common units and a cash distribution of $0.1447 per unit per quarter (or $0.58 per unit on an annualized basis) on all of the subordinated units, or only approximately 35.1% of the minimum quarterly distribution. While the fourth quarter is not complete, based on our internal preliminary results of operations, we estimate that available cash generated during the three months ending December 31, 2010 would not have been sufficient to make a cash distribution at the minimum quarterly distribution of $0.4125 per unit on all of the common units, subordinated units, and general partner units if such units had been outstanding during the entire fourth quarter of 2010. The number of outstanding common and subordinated units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.
 
Unaudited pro forma available cash gives effect on a pro forma basis to the administrative services fee our general partner will pay to Quantum Resources Management pursuant to the service agreement with our general partner. The administrative service fee is a quarterly fee equal to 3.5% of our Adjusted EBITDA generated during the preceding quarter, calculated prior to the payment of the fee.
 
We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus and the acquisition of all of our properties actually been completed as of the dates presented. In addition, cash available to pay distributions is primarily a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of unaudited pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in an earlier period.


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The following table illustrates, on an unaudited pro forma basis, for the year ended December 31, 2009 and the twelve months ended September 30, 2010, the amount of available cash that would have been available for distribution to our unitholders, assuming that the formation transactions, the acquisition of all of the Partnership Properties and this offering had been consummated on January 1, 2009 and October 1, 2009, respectively. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.
 
QR Energy, LP
 
Unaudited Pro Forma Cash Available for Distribution
 
                 
    Pro Forma  
    Year Ended
    Twelve Months Ended
 
    December 31, 2009     September 30, 2010  
    (in thousands, except per unit data)  
 
Net income (loss)
  $ (43,387 )   $ 24,832  
Plus:
               
Interest expense (including amortization of debt issuance costs)
    7,770       7,770  
Interest (income)
           
Unrealized losses (gains) on commodity derivative contracts
    54,628       1,292  
Depletion, depreciation and amortization
    24,400       24,400  
Accretion of asset retirement obligations
    827       1,032  
Impairment of long-lived assets
    13,912        
General and administrative expense in excess of the administrative services fee(1)
    8,839       11,261  
                 
Adjusted EBITDA(1)(2)
  $ 66,989     $ 70,587  
Less:
               
Cash interest expense(3)
    6,795       6,795  
Estimated average maintenance capital expenditures(4)
    12,500       12,500  
                 
Available cash(1)
  $ 47,694     $ 51,292  
                 
Annualized distributions per unit
  $ 1.65     $ 1.65  
Estimated annual cash distributions:
               
Distributions on common units held by purchasers in this offering
  $ 24,750     $ 24,750  
Distributions on common units held by affiliates of the Fund
    22,354       22,354  
Distributions on subordinated units
    11,791       11,791  
Distributions on general partner units
    59       59  
                 
Total estimated annual cash distributions
  $ 58,954     $ 58,954  
                 
(Shortfall)
  $ (11,260 )   $ (7,662 )
                 
 
 
(1) On a pro forma basis, we estimate that the general and administrative expenses that would have been allocated to us under GAAP would have been $11.3 million and $13.8 million for the year ended December 31, 2009 and the twelve months ended September 30, 2010, respectively, which was derived from our pro forma financial statements. Under our general partner’s services agreement, from the closing of this offering through December 31, 2012, Quantum Resources Management will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. Such amount is estimated to be approximately $2.4 million and $2.6 million for the year ended December 31, 2009


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and the twelve months ended September 30, 2010, respectively. While the fee is calculated based upon the Adjusted EBITDA from the previous quarter, the amounts provided above are calculated for current periods for illustrative purposes. After December 31, 2012, our general partner will reimburse Quantum Resources Management under the services agreement for all general and administrative expenses allocated by Quantum Resources Management to us, and we will reimburse our general partner for such amounts. This amount does not include all general and administrative expense that will be incurred by us or on our behalf. Such additional costs that are paid by the Fund on our behalf will be treated as a non-cash expense to us and recorded as a capital contribution. For example, if we were required to pay in cash the full amount of such additional costs, our pro forma Adjusted EBITDA and available cash would each be reduced by a corresponding amount.
 
(2) We define Adjusted EBITDA as net income plus interest expense, including realized and unrealized gains and losses on interest rate derivative contracts, unrealized losses on commodity derivative contracts, depletion, depreciation and amortization, accretion of asset retirement obligations, impairments, and general administrative expenses that are allocated to us in accordance with GAAP in excess of the administrative services fee paid by our general partner and reimbursed by us, less interest income and unrealized gains on commodity derivative contracts. We have provided Adjusted EBITDA in this prospectus because we believe it provides investors with additional information to measure our liquidity. Adjusted EBITDA is not a presentation made in accordance with GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA has important limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Please read “Prospectus Summary — Summary Historical and Pro Forma Financial Data” on page 22.
 
(3) In connection with this offering, we intend to enter into a new $750 million credit agreement under which we expect to incur approximately $225 million of borrowings upon the closing of this offering. The pro forma cash interest expense is based on $225 million of borrowings at an assumed weighted-average rate of 3.02%.
 
(4) Historically, our predecessor did not make a distinction between maintenance and growth capital expenditures. For purposes of the presentation of Partnership Unaudited Pro Forma Cash Available for Distribution, we have estimated that approximately $12.5 million of our predecessor’s capital expenditures were maintenance capital expenditures for the Partnership Properties for each of the respective periods, which reflects our estimate of the average annual maintenance capital expenditures necessary to maintain our production through 2015 based on the 2011 forecasted production level of 5.0 MBoe/d based on our reserve report dated June 30, 2010.
 
Estimated Adjusted EBITDA for the Twelve Months Ending December 31, 2011
 
Based upon the assumptions and considerations set forth in the table below, to fund distributions to our unitholders at our minimum quarterly distribution of $0.4125 per common, subordinated and general partner unit, or $59.0 million in the aggregate, for the twelve months ending December 31, 2011, our Adjusted EBITDA for the twelve months ending December 31, 2011 must be at least $78.6 million. The number of outstanding common and subordinated units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.
 
We believe that we will be able to generate this estimated Adjusted EBITDA based on the assumptions set forth in “— Assumptions and Considerations” beginning on page 81. We can give you no assurance, however, that we will generate this amount of estimated Adjusted EBITDA. This estimated Adjusted EBITDA should not be viewed as management’s projection of the actual amount of Adjusted EBITDA that we will generate during the twelve month period ending December 31, 2011. There will likely be differences between our estimated Adjusted EBITDA and our actual results, and those


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differences could be material. If we fail to generate the estimated Adjusted EBITDA contained in our forecast, we may not be able to pay the minimum quarterly distribution on our common units.
 
Management has prepared the prospective financial information that is the basis of our estimated Adjusted EBITDA below to substantiate our belief that we will have sufficient cash to pay the minimum quarterly distribution to all our common unitholders, subordinated unitholders and our general partner units for the twelve months ending December 31, 2011. This prospective financial information is a forward-looking statement and should be read together with the historical and unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 112. This prospective financial information was not prepared with a view toward complying with the published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate sufficient Adjusted EBITDA to pay the minimum quarterly distribution to all of our common unitholders and subordinated unitholders, as well as in respect of the general partner units, for the twelve months ending December 31, 2011. However, this prospective financial information is not fact and should not be relied upon as being necessarily indicative of our actual results of operations, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information. Please read “— Assumptions and Considerations” beginning on page 81.
 
The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither PricewaterhouseCoopers LLP nor KPMG LLP has compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP and KPMG LLP do not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP report and the KPMG LLP report included in the registration statement relate to our predecessor’s historical financial information. Those reports do not extend to the prospective financial information and should not be read to do so.
 
When considering this prospective financial information, you should keep in mind the risk factors and other cautionary statements under “Risk Factors” beginning on page 29. Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the estimated Adjusted EBITDA sufficient to pay the minimum quarterly distributions to holders of our common, subordinated and general partner units for the twelve months ending December 31, 2011.
 
We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.
 
As a result of the factors described in “— Our Estimated Adjusted EBITDA” beginning on page 78 and in the footnotes to the table in that section, we believe we will be able to pay cash distributions at the minimum quarterly distribution of $0.4125 per unit on all outstanding common, subordinated and general partner units for each full calendar quarter in the year ending December 31, 2011. The number of outstanding common units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.
 
Our Estimated Adjusted EBITDA
 
To pay the minimum quarterly distribution to our unitholders of $0.4125 per unit per quarter over the four consecutive calendar quarters ending December 31, 2011, our cumulative cash available to pay distributions must be at least approximately $59.0 million over that period. We have calculated that the


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amount of estimated Adjusted EBITDA for the twelve months ending December 31, 2011 that will be necessary to generate cash available to pay aggregate distributions of approximately $59.0 million over that period is approximately $78.6 million. Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities or any other measure calculated in accordance with GAAP.
 
Adjusted EBITDA is a significant financial metric that will be used by our management to indicate (prior to the establishment of any reserves by the board of directors of our general partner) the cash distributions we expect to pay to our unitholders. Specifically, we intend to use this financial measure to assist us in determining whether we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. As used in this prospectus, the term “Adjusted EBITDA” means the sum of net income (loss) adjusted by the following to the extent included in calculating such net income (loss):
 
  •  Plus:
 
  •  Interest expense, including realized and unrealized gains and losses on interest rate derivative contracts;
 
  •  Depletion, depreciation and amortization;
 
  •  Accretion of asset retirement obligations;
 
  •  Unrealized losses on commodity derivative contracts;
 
  •  Impairments; and
 
  •  General and administrative expenses that are allocated to us in accordance with GAAP in excess of our administrative services fee paid by our general partner and reimbursed by us.
 
  •  Less:
 
  •  Interest income; and
 
  •  Unrealized gains on commodity derivative contracts.


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QR Energy, LP
 
Estimated Adjusted EBITDA
 
         
    Forecasted for
 
    Twelve Months Ending
 
    December 31, 2011  
    ($ in millions, except
 
    per unit amounts)  
 
Operating revenue and realized commodity derivative gains (losses)(1):
  $ 115.3  
Less:
       
Production expenses
    21.6  
Production and ad valorem taxes
    6.1  
General and administrative expenses(2)
    12.4  
Depletion, depreciation and amortization expense
    24.7  
Accretion of asset retirement obligations
    1.0  
Interest expense
    7.7  
         
Net income excluding unrealized derivative gains (losses)
  $ 41.8  
Adjustments to reconcile Net income excluding unrealized derivative gains (losses) to estimated Adjusted EBITDA:
       
Add:
       
Depletion, depreciation and amortization expense
  $ 24.7  
Accretion of asset retirement obligations
    1.0  
General and administrative expense in excess of the administrative service fee(2)
    9.3  
Interest expense
    7.7  
         
Estimated Adjusted EBITDA(2)(3)
  $ 84.5  
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
       
Less:
       
Cash interest expense
  $ 7.1  
Estimated average maintenance capital expenditures(4)
    12.5  
         
Estimated cash available for distribution(2)
  $ 64.9  
Annualized minimum quarterly distribution per common unit
  $ 1.65  
Estimated annual cash distributions(5):
       
Distributions on common units held by purchasers in this offering
  $ 24.7  
Distributions on common units held by the Fund
    22.4  
Distributions on subordinated units
    11.8  
Distributions on general partner units
    0.1  
         
Total estimated annual cash distributions
  $ 59.0  
         
Excess cash available for distribution(6)
  $ 5.9  
         
Minimum estimated Adjusted EBITDA:
       
Estimated Adjusted EBITDA(2)(3)
  $ 84.5  
Less:
       
Excess cash available for distribution(6)
    5.9  
         
Minimum estimated Adjusted EBITDA
  $ 78.6  
         
 
 
(1) Includes the forecasted effect of cash settlements of commodity derivative contracts. This amount does not include unrealized commodity derivative gains (losses), as such amounts represent non-cash items and cannot be reasonably estimated in the forecast period.
 
(2) We estimate that the general and administrative services allocated to us under GAAP will be $12.4 million for the year ending December 31, 2011, which was calculated by annualizing our pro forma general and administrative expense of $12.3 million, less $3.0 million in expenses attributable


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to this offering for the nine months ended September 30, 2010. Under our general partner’s services agreement, from the closing of this offering through December 31, 2012, Quantum Resources Management will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. Such amount is estimated to be approximately $3.1 million for the year ending December 31, 2011. This fee does not include all general and administrative expenses that will be incurred by us or on our behalf. Such additional costs that are paid by the Fund on our behalf will be treated as a non-cash expense to us and recorded as a capital contribution and have therefore been added back in the calculation of Adjusted EBITDA. After December 31, 2012, our general partner will be required to reimburse Quantum Resources Management (and we will reimburse our general partner) for all general and administrative costs that are incurred on our behalf. We expect that the manner in which Quantum Resources Management will allocate general and administrative costs to us after December 31, 2012 may differ from the manner in which such costs are allocated to us for GAAP purposes because we do not expect Quantum Resources Management to allocate to us any of the Fund’s general and administrative costs that are not applicable to our business. For example, if, in 2011, we were required to reimburse our general partner for its reimbursement of Quantum Resources Management for the full amount of the general and administrative costs allocated to us for GAAP purposes, our estimated Adjusted EBITDA and estimated cash available for distribution for the twelve months ending December 31, 2011 would each be reduced by approximately $9.3 million.
 
(3) We define Adjusted EBITDA as: Net income, plus interest expense, including realized and unrealized gains and losses on interest rate derivative contracts, unrealized losses on commodity derivative contracts, depletion, depreciation and amortization, accretion of asset retirement obligations, impairments, and general and administrative expenses that are allocated to us in accordance with GAAP in excess of the administrative services fee paid by our general partner and reimbursed by us, less interest income and unrealized gains on commodity derivative contracts. We have provided Adjusted EBITDA in this prospectus because we believe it provides investors with additional information to measure our liquidity. Adjusted EBITDA is not a presentation made in accordance with GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA has important limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Please read “Prospectus Summary — Summary Historical and Pro Forma Financial Data” on page 22.
 
(4) In calculating the estimated cash available for distribution, we have included our estimated maintenance capital expenditures for the year ending December 31, 2011. We expect to incur approximately $3.7 million of capital expenditures for the twelve months ending December 31, 2011 based on our reserve report dated June 30, 2010, but will reserve an additional $8.8 million during 2011 to maintain the current level of production from our assets. We estimate that an average annual capital expenditure of $12.5 million will enable us to maintain the current level of production from our assets through December 31, 2015. We have not included any reserves beyond estimated maintenance capital expenditures and cash interest expense in calculating the estimated cash available for distribution.
 
(5) The number of outstanding common units assumed herein does not include any common units that may be issued under the long-term incentive plan that our general partner is expected to adopt prior to the closing of this offering.
 
(6) We plan to retain any excess cash for general partnership purposes.
 
Assumptions and Considerations
 
Based upon the specific assumptions outlined below with respect to the twelve months ending December 31, 2011, we expect to generate estimated Adjusted EBITDA sufficient to establish reserves for


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capital expenditures and to pay the minimum quarterly distribution on all common, subordinated and general partner units for the twelve months ending December 31, 2011.
 
While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay quarterly cash distributions equal to our minimum quarterly distribution (absent borrowings under our new revolving credit facility), or any amount, on all common, subordinated and general partner units, in which event the market price of our common units may decline substantially. We are unlikely to be able to sustain our minimum quarterly distribution without making acquisitions or other capital expenditures that maintain our asset base. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our asset base, we will be unable to pay distributions at the then-current level from cash generated from operations and would therefore expect to reduce our distributions. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” beginning on page 29 and “Forward-Looking Statements” on page 250. Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.
 
Operations and Revenue
 
Production.  The following table sets forth information regarding net production of oil and natural gas on a pro forma basis for the year ended December 31, 2009, twelve months ended September 30, 2010 and on a forecasted basis for the year ending December 31, 2011:
 
                         
          Pro Forma
       
    Pro Forma
    Twelve Months
    Forecasted
 
    Year Ended
    Ended
    Year Ending
 
    December 31, 2009     September 30, 2010     December 31, 2011  
 
Annual production(1):
                       
Oil (MBbl)
    931       920       1,047  
Natural gas (MMcf)
    5,151       4,931       3,970  
NGLs (MBbl)
    137       148       121  
                         
Total (MBoe)
    1,927       1,890       1,829  
Average net production:
                       
Oil (Bbl/d)
    2,551       2,521       2,868  
Natural gas (Mcf/d)
    14,113       13,510       10,878  
NGLs (Bbl/d)
    377       405       331  
                         
Total (Boe/d)
    5,280       5,178       5,011  
 
 
(1) In order to approximate the effect of our 8.05% overriding oil royalty interest for the pro forma and forecasted periods, we have included 8.05% of the oil production from the Fund’s 92% working interest in the Jay Field during those periods, or 56.1 MBbls of oil for the twelve months ended September 30, 2010 and 0.7 MBbls of oil for the year ended December 31, 2009 due to the shut-in of the Jay Field during that period. In addition, we have included 8.05% of the estimated forecasted oil production from the Fund’s 92% working interest in the Jay Field for the year ending December 31, 2011, or 103 MBbls of oil based on our reserve report dated June 30, 2010. For more information regarding our overriding oil royalty interest in the Jay Field, please read “Business and Properties — Summary of Oil and Natural Gas Properties and Projects — The Gulf Coast Area — Overriding Oil Royalty Interest in Jay Field” on page 154.


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We estimate that our oil and natural gas production for the year ending December 31, 2011 will be 1.8 MMBoe as compared to 1.9 MMBoe on a pro forma basis for each of the years ended December 31, 2009 and twelve months ended September 30, 2010. The forecast reflects an 8% annualized natural production decline that is offset by production growth resulting from $3.7 million of maintenance capital expenditures to be spent during the twelve months ending December 31, 2011. We intend to maintain our forecasted 2011 production level of 5.0 MBoe/d over the long term with cash generated from operations.
 
Prices.  The table below illustrates the relationship between average oil and natural gas realized sales prices and the average NYMEX prices on a pro forma basis for the year ended December 31, 2009 and the twelve months ended September 30, 2010 and our forecast for the year ending December 31, 2011:
 
                         
          Pro Forma
       
    Pro Forma
    Twelve Months
    Forecasted
 
    Year Ended
    Ended
    Year Ending
 
    December 31, 2009     September 30, 2010     December 31, 2011  
 
Average oil sales prices:
                       
NYMEX-WTI oil price per Bbl
  $ 61.80     $ 77.19     $ 80.00  
Differential to NYMEX-WTI oil per Bbl
  $ (5.39 )   $ (3.97 )   $ (4.18 )
Realized oil sales price per Bbl (excluding cash settlements of derivatives)
  $ 56.41     $ 73.22     $ 75.82  
Realized oil sales price per Bbl (including cash settlements of derivatives)(1)(2)
  $ 56.41     $ 73.22     $ 79.72  
Average natural gas sales prices:
                       
NYMEX-Henry Hub natural gas price per MMBtu
  $ 3.99     $ 4.49     $ 4.00  
Differential to NYMEX-Henry Hub natural gas
  $ (0.15 )   $ 0.24     $ (0.16 )
Realized natural gas sales price per Mcf (excluding cash settlements of derivatives)
  $ 3.84     $ 4.73     $ 3.84  
Realized natural gas sales price per Mcf (including cash settlements of derivatives)(1)(2)
  $ 3.84     $ 4.73     $ 6.59  
Average natural gas liquids sales prices:
                       
NYMEX-WTI oil price per Bbl
  $ 61.80     $ 77.19     $ 80.00  
Differential to NYMEX-WTI oil price per Bbl
  $ (28.49 )   $ (31.38 )   $ (33.18 )
Realized natural gas liquids sales price per Bbl (excluding cash settlements of derivatives)(1)(2)
  $ 33.31     $ 45.81     $ 46.82  
Realized natural gas liquids sales price per Bbl (including cash settlements of derivatives)(1)(2)
  $ 33.31     $ 45.81     $ 46.82  
                         
Total combined price (per Boe, excluding cash settlements of derivatives)
  $ 39.91     $ 51.58     $ 54.81  
Total combined price (per Boe, including cash settlements of derivatives)(1)(2)
  $ 39.91     $ 51.58     $ 63.02  


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(1) Average NYMEX futures prices for 2011 as reported on September 9, 2010. For a description of the effect of lower spot prices on cash available for distribution, please read “— Sensitivity Analysis — Commodity Price Changes” on page 91.
 
(2) Our pro forma realized prices do not include gains or losses on commodity derivative contracts. Because the commodity derivative contracts to be contributed to us have been commingled with the properties retained by our predecessor, the historical information associated with these commodity derivative contracts is not available by product type. Accordingly, we have omitted the effects of commodity derivative contracts from our pro forma average sales prices per Bbl and Mcf above. After contribution of certain commodity derivative contracts by the Fund at the closing of this offering, we will have commodity derivative contracts covering 80% of our forecasted oil and natural gas production for the year ending December 31, 2011.
 
Price Differentials.  As is typical in the oil and natural gas industry and as reflected in our reserve report dated June 30, 2010, we report our natural gas production and estimated reserves in Mcf, while we sell our natural gas production and enter into commodity derivative contracts that measure natural gas in MMBtu, a measure of the heating capacity of natural gas. The following table presents the average Btu content for our natural gas production by operating area:
 
         
Operating Area
  MMBtu per Mcf
 
Permian Basin
    1.242  
Ark-La-Tex
    1.159  
Mid-Continent
    1.127  
Gulf Coast
    1.109  
Weighted Average
    1.163  
 
To the extent the Btu content for our natural gas production is above 1.000 MMBtu per Mcf, we will receive a price premium relative to the NYMEX-Henry Hub price.
 
However, our natural gas production has historically sold at a negative basis differential from the NYMEX-Henry Hub price primarily due to the distance of the production attributable to our operating areas from the Henry Hub, which is located in Louisiana, and other location and transportation cost factors. In addition, our oil production, which consists of a combination of sweet and sour oil, typically sells at a discount to the NYMEX-WTI price due to quality and location differentials.
 
The adjustments we have made to reflect the basis differentials for our forecasted production during the twelve months ending December 31, 2011 are presented in the following table and shown per Bbl for oil and per MMBtu as well as per Mcf for natural gas, as reflected in our reserve report dated June 30, 2010:
 
                         
    Oil   Natural Gas
Operating Area
  Per Bbl   Per MMBtu   Per Mcf
 
Permian Basin
  $ (4.23 )   $ (0.01 )   $ 0.51  
Ark-La-Tex
  $ (3.41 )   $ (0.99 )   $ (0.39 )
Mid-Continent
  $ (4.32 )   $ (1.21 )   $ (0.36 )
Gulf Coast
  $ (5.33 )   $ (0.55 )   $ (0.02 )
Weighted Average
  $ (4.25 )   $ (0.84 )   $ (0.21 )
 
In addition, some of our pro forma production has transportation, gathering, and marketing charges deducted from the prices we realize. In the Permian Basin and Mid-Continent areas, most of these charges are inclusive in the net pricing received from the gathering and processing companies. In areas where firm transportation capacity is contracted separately from the counterparties purchasing the natural gas, an additional adjustment is made as a deduction. The Gulf Coast area currently incurs no such additional charges. The Ark-La-Tex area has these separate gathering and transportation charges that average approximately $0.19 per MMBtu or $0.22 per Mcf. The transportation costs are necessary to minimize risk of flow interruption to the markets.


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Use of Commodity Derivative Contracts.  At the closing of this offering, the Fund expects to assign specific commodity derivative contracts to us covering 1.4 MMBoe, or approximately 80%, of our forecasted total oil and natural gas production of 1.7 MMBoe for the year ending December 31, 2011. The assigned commodity derivative contracts will consist of swap agreements against the NYMEX-WTI and NYMEX-Henry Hub prices for oil and natural gas, respectively. The table below shows the volumes and prices of our commodity derivative contracts for the year ending December 31, 2011:
 
                 
    Swaps
        Weighted
    Bbl   Average Price
 
Oil:
               
January 2011 — December 2011
    816,800     $ 85.00  
% of forecasted oil production
    78 %        
 
                 
        Weighted
    MMBtu   Average Price
 
Natural gas:
               
January 2011 — December 2011
    3,350,100     $ 7.26  
% of forecasted natural gas production
    84 %        
 
Operating Revenues and Realized Commodity Derivative Gains.  The following table illustrates the primary components of operating revenues and realized commodity derivative gains on a pro forma basis for the year ended December 31, 2009, the twelve months ended September 30, 2010 and on a forecasted basis for the year ending December 31, 2011:
 
                         
          Pro Forma
       
    Pro Forma
    Twelve Months
    Forecasted
 
    Year Ended
    Ended
    Year Ending
 
    December 31, 2009     September 30, 2010     December 31, 2011  
    ($ in millions)  
 
Oil:
                       
Oil revenues
  $ 52.5     $ 67.7     $ 79.4  
Oil derivative contracts gain (loss)(1)
                    4.1  
                         
Total
                  $ 83.5  
Natural gas:
                       
Natural gas revenues
  $ 19.8     $ 23.4     $ 15.2  
Natural gas derivative contracts gain (loss)(1)
                    10.9  
                         
Total
                  $ 26.1  
NGLs:
                       
NGLs revenues
  $ 4.6     $ 6.8     $ 5.7  
NGLs derivative contracts gain (loss)(1)
                     
                         
Total
                  $ 5.7  
                         
Total:
                       
Operating revenues
  $ 76.9     $ 97.9     $ 100.3  
Commodity derivative contracts gain (loss)(1)
    30.4       5.0     $ 15.0  
                         
Operating revenue and realized commodity derivative contract gains
  $ 107.3     $ 102.9     $ 115.3  
                         
 
(1) Our pro forma realized prices do not include gains or losses on commodity derivative contracts. Because the commodity derivative contracts to be contributed to us have been commingled with the properties retained by our predecessor, the pro forma information associated with these commodity derivative contracts is not available by product type. We have given effect to the expected assignment to us at the


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closing of this offering of commodity derivative contracts covering 80% of our anticipated total forecasted oil and natural gas production for the year ending December 31, 2011.
 
Capital Expenditures and Expenses
 
Capital Expenditures.  Our estimated cash reserves for maintenance capital expenditures for the year ending December 31, 2011 of $12.5 million represent our estimate of the average annual maintenance capital expenditures necessary to maintain our production through 2015 based on the 2011 forecasted production level of 5.0 MBoe/d based on our reserve report dated June 30, 2010.
 
We anticipate replacing declining production and reserves through the drilling and completing of wells on our undeveloped properties and through the acquisition of producing and non-producing oil and natural gas properties from the Fund and from third parties. We estimate that we will drill 76 gross (2 net) wells during the forecast period at an aggregate net cost of approximately $2.3 million. We also expect to spend approximately $1.4 million during 2011 on workovers, recompletions and other field-related costs. In addition, we will reserve an additional $8.8 million for capital expenditures during 2011 to maintain the current level of production of our assets. Although we may make acquisitions during the year ending December 31, 2011, our forecast period does not reflect any acquisitions, as we cannot assure you that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase agreements.
 
Lease Operating Expenses.  The following table summarizes lease operating expenses on an aggregate basis and on a per Boe basis for the year ended December 31, 2009 and twelve months ended September 30, 2010, pro forma, and on a forecasted basis for the year ending December 31, 2011:
 
                         
        Pro Forma
   
    Pro Forma
  Twelve Months
  Forecasted
    Year Ended
  Ended
  Year Ending
    December 31, 2009   September 30, 2010   December 31, 2011
    ($ in millions, except per unit amounts)
 
Lease operating expenses
  $ 23.8     $ 22.1     $ 21.6  
Lease operating expenses (per Boe)
  $ 12.34     $ 11.71     $ 11.84  
 
We estimate that our lease operating expenses for the year ending December 31, 2011 will be approximately $21.6 million. On a pro forma basis, for the year ended December 31, 2009 and twelve months ended September 30, 2010, lease operating expenses were $23.8 million and $22.1 million, respectively, with respect to the Partnership Properties. The decrease in forecasted lease operating expenses is mainly a result of lower forecasted volumes during the forecast period compared to the pro forma year ended December 31, 2009 and twelve months ended September 30, 2010.


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Production and Other Taxes.  The following table summarizes production and other taxes before the effects of our commodity derivative contracts on a pro forma basis for the year ended December 31, 2009 and twelve months ended September 30, 2010 and on a forecasted basis for the year ending December 31, 2011:
 
                         
        Pro Forma
   
    Pro Forma
  Twelve Months
  Forecasted
    Year Ended
  Ended
  Year Ending
    December 31, 2009   September 30, 2010   December 31, 2011
    ($ in millions)
 
Oil, natural gas and NGL revenues, excluding the effect of our commodity derivative contracts
  $ 76.9     $ 97.9     $ 100.3  
Production and ad valorem taxes
  $ 5.8     $ 6.2     $ 6.1  
Production and ad valorem taxes as a percentage of revenue
    8 %     6 %     6 %
 
Our production taxes are calculated as a percentage of our oil, natural gas and NGL revenues, excluding the effects of our commodity derivative contracts. In general, as prices and volumes increase, our production taxes increase. As prices and volumes decrease, our production taxes decrease. Additionally, production tax rates vary by state, and as revenues by state vary, our production taxes will increase or decrease. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; however, these valuations are reasonably correlated to revenues, excluding the effects of our commodity derivative contracts. As a result we are forecasting our ad valorem taxes as a percent of revenues, excluding the effects of our commodity derivative contracts. The decrease as a percentage of revenue is partially due to our overriding oil royalty interest in the Jay Field, which is not encumbered by costs, including production and ad valorem taxes.
 
General and Administrative Expenses.  We estimate that the general and administrative expenses allocated to us under GAAP for the year ending December 31, 2011 will be approximately $12.4 million, which was calculated by annualizing our pro forma general and administrative expense of $12.3 million less $3.0 million in expenses attributable to this offering for the nine months ended September 30, 2010. Our total forecasted general and administrative expenses of $12.4 million for the year ending December 31, 2011 compares to approximately $11.3 million and $13.8 million, respectively, of pro forma general and administrative expenses for each of the year ended December 31, 2009 and the twelve months ended September 30, 2010. At the closing of this offering, our general partner will enter into a services agreement with Quantum Resources Management with respect to all general and administrative costs and services it incurs on our general partner’s and our behalf, including the $4.3 million of incremental expenses we expect to incur as a result of becoming a publicly traded partnership, $2.0 million of which are incremental expenses related to the hiring of additional personnel. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs and director compensation. Under the services agreement, Quantum Resources Management will be entitled to a quarterly administrative services fee in cash equal to 3.5% of the Adjusted EBITDA generated during the preceding quarter, calculated prior to the payment of the fee, in exchange for those services through December 31, 2012. The forecasted expense of $12.4 million includes an administrative services fee that represents only a portion of the actual total general and administrative expenses we would expect to incur absent our arrangement under our general partner’s services agreement with Quantum Resources Management. For the forecast period, we estimate that a fee of 3.5% of estimated Adjusted EBITDA for the year ending December 31, 2011, calculated prior to the payment of the fee, will be approximately $3.1 million. General and administrative expenses incurred by our general partner or Quantum Resources Management on our behalf that may


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be allocated to us under GAAP in excess of the administrative services fee paid to Quantum Resources Management will be non-cash items and have therefore been added back in the calculation of Adjusted EBITDA. After December 31, 2012, we will be required to reimburse our general partner for 100% of all general and administrative expenses allocated to us under the services agreement, which could be higher than the fee based on our Adjusted EBITDA under the services agreement for 2011 and 2012. If our general partner grants awards of bonuses and unit-based compensation to officers and employees in the future, those awards may adversely impact our cash available for distribution. However, we have made no assumptions with respect to these items in the forecast because our general partner has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted. Awards of bonuses and unit-based compensation granted during the year ending December 31, 2011 are not subject to a maximum amount, except that unit-based awards are limited under our long term incentive plan.
 
Management Incentive Fee.  We have assumed for purposes of the forecast that no management incentive fee will be paid during the forecast period.
 
Depletion, Depreciation and Amortization Expense.  We estimate that our depletion, depreciation and amortization expense for the year ending December 31, 2011 will be approximately $24.7 million, as compared to $24.4 million and $24.4 million, respectively, on a pro forma basis for the year ending December 31, 2009 and for the twelve months ended September 30, 2010. The forecasted depletion of our oil and natural gas properties is based on the production estimates in our reserve report dated June 30, 2010. Our capitalized costs are calculated using the full cost method of accounting. For a detailed description of the full cost method of accounting, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” beginning on page 136.
 
Cash Interest Expense.  We estimate that at the closing of this offering we will borrow approximately $225 million in revolving debt under our new $750 million credit facility. We estimate that the borrowings will bear interest at a weighted average rate of approximately 3.1%. Based on these assumptions, we estimate that our cash interest expense for the year ending December 31, 2011 will be $7.1 million as compared to $6.8 million on a pro forma basis for each of the year ended December 31, 2009 and the twelve months ended September 30, 2010.
 
We expect that our new credit facility will contain financial covenants that require us to maintain a leverage ratio of not more than 4.0 to 1.0 and a current ratio of not less than 1.0 to 1.0. Additionally, the new credit facility will prohibit us from paying distributions to our unitholders if our borrowings under the new credit facility exceed 95% of the borrowing base then in effect. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — New Credit Facility” on page 123 for additional detail regarding the covenants and restrictive provisions to be included in our new credit facility. We expect that the new credit facility will not require any cash expenditures on our part other than cash interest expense that would affect our cash available for distribution. As a result, based on the assumptions used in preparing the estimates set forth above, the new credit facility, including the financial covenants and borrowing base utilization limitation discussed above, will not have any effect upon our ability to pay the estimated distributions to our unitholders during the forecast period.
 
Regulatory, Industry and Economic Factors
 
Our forecast for the year ending December 31, 2011 is based on the following significant assumptions related to regulatory, industry and economic factors:
 
  •  There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;
 
  •  There will not be any major adverse change in commodity prices or the energy industry in general;


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  •  Market, insurance and overall economic conditions will not change substantially; and
 
  •  We will not undertake any extraordinary transactions that would materially affect our cash flow.
 
Forecasted Distributions
 
We expect that aggregate quarterly distributions of available cash on our common units, subordinated units and general partner units for the year ending December 31, 2011 will be approximately $59.0 million. Quarterly distributions of available cash will be paid within 45 days after the close of each calendar quarter.
 
While we believe that the assumptions we have used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic regulatory and competitive risks and uncertainties, including those described in “Risk Factors” beginning on page 29 that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full minimum quarterly distribution or any amount on all our outstanding common, subordinated and general partner units in respect of the four calendar quarters ending December 31, 2011 or thereafter, in which event the market price of the common units may decline materially.
 
Sensitivity Analysis
 
Our ability to generate sufficient cash from operations to pay distributions to our unitholders is a function of two primary variables: (i) production volumes and (ii) commodity prices. In the paragraphs below, we discuss the impact that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the minimum quarterly distributions on our outstanding common units and subordinated units for the year ending December 31, 2011.


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Production Volume Changes
 
The following table shows estimated Adjusted EBITDA under production levels of 90%, 100% and 110% of the production level we have forecasted for the year ending December 31, 2011. The estimated Adjusted EBITDA amounts shown below are based on the assumptions used in our forecast.
 
                         
    Percentage of Forecasted Net Production  
    90%     100%     110%  
    ($ in millions, except per unit amounts)  
 
Forecasted net production:
                       
Oil (MBbl)
    942       1,047       1,151  
Natural gas (MMcf)
    3,573       3,970       4,367  
NGLs (MBbl)
    109       121       133  
                         
Total (MBoe)
    1,646       1,829       2,012  
                         
Oil (Bbl/d)
    2,581       2,868       3,154  
Natural gas (Mcf/d)
    9,790       10,878       11,966  
NGLs (Bbl/d)
    298       331       364  
                         
Total (Boe/d)
    4,510       5,011       5,512  
                         
Forecasted prices:
                       
NYMEX-WTI oil price (per Bbl)
  $ 80.00     $ 80.00     $ 80.00  
Realized oil price (per Bbl) (excluding derivatives)
  $ 75.82     $ 75.82     $ 75.82  
Realized oil price (per Bbl) (including derivatives)
  $ 80.15     $ 79.72     $ 79.36  
                         
NYMEX-Henry Hub natural gas price (per MMBtu)
  $ 4.00     $ 4.00     $ 4.00  
Realized natural gas price (per Mcf) (excluding derivatives)
  $ 3.84     $ 3.84     $ 3.84  
Realized natural gas price (per Mcf) (including derivatives)
  $ 6.89     $ 6.59     $ 6.34  
                         
NYMEX-WTI oil price (per Bbl)
  $ 80.00     $ 80.00     $ 80.00  
Realized natural gas liquids price (per Bbl) (excluding derivatives)
  $ 46.82     $ 46.82     $ 46.82  
Realized natural gas liquids price (per Bbl) (including derivatives)
  $ 46.82     $ 46.82     $ 46.82  
                         
Forecasted Adjusted EBITDA projection:
                       
Operating revenue
  $ 90.2     $ 100.3     $ 110.3  
Realized derivative gains (losses)
    15.0       15.0       15.0  
                         
Total revenue and realized derivative gains (losses)
  $ 105.2     $ 115.3     $ 125.3  
Oil and natural gas production expenses
    19.5       21.6       23.8  
Production and ad valorem taxes
    5.5       6.1       6.7  
Administrative services fee
    2.8       3.1       3.3  
                         
Estimated Adjusted EBITDA
  $ 77.4     $ 84.5     $ 91.5  
Minimum estimated Adjusted EBITDA
  $ 78.6     $ 78.6     $ 78.6  
Excess cash available for distribution
  $ (1.2 )   $ 5.9     $ 12.9  


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Commodity Price Changes
 
The following table shows estimated Adjusted EBITDA under various assumed NYMEX-WTI oil and natural gas prices for the year ending December 31, 2011. For the year ending December 31, 2011, we have assumed that, at the closing of this offering, the Fund will contribute to us commodity derivative contracts covering 1.4 MMBoe, or approximately 80% of our estimated total oil and natural gas production for the year ending December 31, 2011, at a fixed price of $85.00 per Bbl of oil and $7.26 per MMBtu of natural gas. In addition, the estimated Adjusted EBITDA amounts shown below are based on forecasted realized commodity prices that take into account our average NYMEX commodity price differential assumptions. We have assumed no changes in our production based on changes in prices.
 
                                 
    ($ in millions, except per unit amounts)  
 
NYMEX-Henry Hub natural gas price (per MMBtu):
  $ 3.25     $ 3.75     $ 4.25     $ 4.75  
NYMEX-WTI oil price (per Bbl):
  $ 65.00     $ 75.00     $ 85.00     $ 95.00  
                                 
Forecasted net production:
                               
Oil (MBbl)
    1,047       1,047       1,047       1,047  
Natural gas (MMcf)
    3,970       3,970       3,970       3,970  
NGLs (MBbl)
    121       121       121       121  
                                 
Total (MBoe)
    1,829       1,829       1,829       1,829  
Oil (Bbl/d)
    2,868       2,868       2,868       2,868  
Natural gas (Mcf/d)
    10,878       10,878       10,878       10,878  
NGLs (Bbl/d)
    331       331       331       331  
                                 
Total (Boe/d)
    5,011       5,011       5,011       5,011  
                                 
Forecasted prices:
                               
NYMEX-WTI oil price (per Bbl)
  $ 65.00     $ 75.00     $ 85.00     $ 95.00  
Realized oil price (per Bbl) (excluding derivatives)
  $ 61.60     $ 71.08     $ 80.55     $ 90.03  
Realized oil price (per Bbl) (including derivatives)
  $ 77.21     $ 78.88     $ 80.55     $ 82.23  
                                 
NYMEX-Henry Hub natural gas price (per MMBtu)
  $ 3.25     $ 3.75     $ 4.25     $ 4.75  
Realized natural gas price (per Mcf) (excluding derivatives)
  $ 3.12     $ 3.60     $ 4.08     $ 4.55  
Realized natural gas price (per Mcf) (including derivatives)
  $ 6.50     $ 6.56     $ 6.62     $ 6.67  
                                 
NYMEX-WTI oil price (per Bbl)
  $ 65.00     $ 75.00     $ 85.00     $ 95.00  
Realized natural gas liquids price (per Bbl) (excluding derivatives)
  $ 38.04     $ 43.89     $ 49.75     $ 55.60  
Realized natural gas liquids price (per Bbl) (including derivatives)
  $ 38.04     $ 43.89     $ 49.75     $ 55.60  
                                 
Forecasted Adjusted EBITDA projection:
                               
Operating revenue
  $ 81.5     $ 94.0     $ 106.5     $ 119.1  
Realized derivative gains (losses)
    29.8       19.9       10.1       0.2  
                                 
Total revenue and realized derivative gains (losses)
  $ 111.3     $ 113.9     $ 116.6     $ 119.3  
Oil and natural gas production expenses
  $ 21.6     $ 21.6     $ 21.6     $ 21.6  
Production and ad valorem taxes
    5.2       5.8       6.4       7.0  
Administrative services fee
    3.0       3.0       3.1       3.2  
                                 
Estimated Adjusted EBITDA
  $ 81.5     $ 83.5     $ 85.5     $ 87.5  
Minimum estimated Adjusted EBITDA
    78.6       78.6       78.6       78.6  
Excess cash available for distribution
  $ 2.9     $ 4.9     $ 6.9     $ 8.9  
 
We expect to adopt a hedging policy to reduce the impact to our cash flows from commodity price volatility under which we intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated oil and natural gas production over a three-to-five year period at a given point in time. As opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative contracts in connection with material increases in our


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estimated reserves and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of opportunities to modify our derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. Implementation of such policy will mitigate, but will not eliminate, our sensitivity to short term changes in prevailing natural gas prices.
 
As NYMEX oil and natural gas prices decline, our estimated Adjusted EBITDA does not decline proportionately for two reasons: (1) the effects of our commodity derivative contracts and (2) production taxes, which are calculated as a percentage of our oil and natural gas revenues, excluding the effects of our commodity derivative contracts, and which decrease as commodity prices decline. Furthermore, we have assumed no changes in estimated production or oil and natural gas operating costs during the year ending December 31, 2011. However, over the long term, a sustained decline in oil and natural gas prices would likely lead to a decline in production and oil and natural gas operating costs as well as a reduction in our realized oil and natural gas prices. Therefore, the foregoing table is not illustrative of all of the potential effects of changes in commodity prices for periods subsequent to December 31, 2011.


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PROVISIONS OF OUR PARTNERSHIP AGREEMENT
RELATING TO CASH DISTRIBUTIONS AND THE MANAGEMENT INCENTIVE FEE
 
Our general partner, QRE GP, LLC, will be owned 50% by an entity controlled by Mr. Neugebauer and Mr. VanLoh and 50% by an entity controlled by Mr. Smith and Mr. Campbell, and Messrs. Neugebauer, VanLoh, Smith and Campbell are indirectly entitled to all or a significant portion of the distributions that we make in respect of our general partner units and the amounts we pay in respect of the management incentive fee to our general partner (including any cash distributions made in respect of any converted Class B units held by our general partner), subject to the terms of the limited liability company agreement of QRE GP, LLC.
 
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions and the management incentive fee.
 
Distributions of Available Cash
 
General
 
Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2010, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution payable in respect of the quarter ending December 31, 2010 for the period from the closing of the offering through December 31, 2010.
 
Definition of Available Cash
 
Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:
 
  •  less, the amount of cash reserves established by our general partner to:
 
  •  provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;
 
  •  comply with applicable law, any of our debt instruments or other agreements; or
 
  •  provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for common and subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter and the next four quarters);
 
  •  plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.
 
Working capital borrowings are borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.
 
Intent to Distribute the Minimum Quarterly Distribution
 
We intend to distribute to the holders of common, Class B, if any, and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.4125 per unit, or $1.65 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and payment of fees and expenses, including payments (or reserving for payment) of fees


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(including the management incentive fee, if any, that will be due in connection with payment of the distribution) and expenses to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.
 
General Partner Interest and Management Incentive Fee
 
Initially, our general partner will be entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our general partner’s 0.1% interest in us is represented by general partner units for allocation and distribution purposes. At the consummation of this offering, our general partner’s 0.1% interest in us will be represented by 35,729 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest. Our general partner’s initial 0.1% interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units to the Fund upon expiration of the underwriters’ option to purchase additional common units, the issuance of common units upon conversion of outstanding Class B units or the issuance of common units upon conversion of outstanding subordinated units) and our general partner does not contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its 0.1% general partner interest.
 
For each quarter for which we have paid cash distributions that equaled or exceeded 115% of our minimum quarterly distribution (our “Target Distribution”), or $0.4744 per unit, our general partner will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of our management incentive fee base, which will be an amount equal to the sum of:
 
  •  the future net revenue of our estimated proved oil and natural gas reserves, discounted to present value at 10% per annum and calculated based on SEC methodology, adjusted for our commodity derivative contracts; and
 
  •  the fair market value of our assets, other than our estimated oil and natural gas reserves and our commodity derivative contracts, that principally produce qualifying income for federal income tax purposes, at such value as may be determined by the board of directors of our general partner and approved by the conflicts committee of our general partner’s board of directors.
 
In addition, subject to certain limitations, our general partner will have the continuing right from time to time to convert into common units up to 80% of such management incentive fee at the end of the subordination period. After each such conversion, the amount on which the management incentive fee is based for future periods will be reduced. The reduction in the management incentive fee as a result of any conversion will directly offset the increase in distributions required by the newly issued Class B units, but the management incentive fee may the