e424b1

Filed Pursuant to Rule 424(b)(1)

Registration No. 333-169664

PROSPECTUS

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

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.

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

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.

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.

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

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

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.

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.

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.

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	%


(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.

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


		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

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,

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.

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.

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.


		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


		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.


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.


		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


		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.


		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”.

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

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.

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

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

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


		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.

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;


	•	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.

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

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

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


	•	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

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

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

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.

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.

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.

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

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

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.

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

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.

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

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

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.

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


		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.

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.

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

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.

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

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.

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

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.

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.

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

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.

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;


	•	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.

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.

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.

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

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.

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.

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.

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.

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.

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


		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


		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.

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.

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

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.

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


		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

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

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.

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


		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

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.

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


(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.

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


		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.

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

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;


	•	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.

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

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

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.

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

(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 thereafter increase over time. For more information regarding the management incentive fee, please read “— 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.

Operating Surplus and Capital Surplus

General

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

Operating Surplus

Operating surplus for any period consists of:


	•	$40.0 million (as described below); plus

	•	all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, which include the following:


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

	•	sales of equity interests; and

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

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


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

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

	•	cash distributions paid on equity issued to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less

	•	all of our operating expenditures (as described below) after the closing of this offering; less

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

	•	all working capital borrowings not repaid within twelve months after having been incurred; less

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

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $40.0 million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, (as described above), certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

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

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


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

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

	•	growth capital expenditures;

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

	•	investment capital expenditures;

	•	payment of transaction expenses relating to interim capital transactions;

	•	distributions to our partners; or

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

Capital Surplus

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


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

	•	sales of our equity interests; and

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

Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Estimated maintenance capital expenditures reduce operating surplus, but growth capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not.

Maintenance capital expenditures are those capital expenditures required to maintain our asset base over the long term. We expect that a primary component of maintenance capital expenditures will be capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of any replacement asset that is paid in respect of the period from such financing until the earlier to occur of the date that any such construction, replacement, acquisition or improvement of a capital improvement or construction replacement, acquisition or improvement of a capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of. Plugging and abandonment cost will also constitute maintenance capital expenditures. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and adjusted operating surplus if we subtracted actual maintenance capital expenditures from operating surplus. To address this issue, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain our asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner’s board of directors. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 70.

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


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

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

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

	•	it will reduce the likelihood that a large maintenance capital expenditure during a particular quarter will prevent the payment of a management incentive fee to our general partner in respect of a particular quarter since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

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

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

As described above, neither investment capital expenditures nor growth capital expenditures will be included in operating expenditures, and thus will not reduce operating surplus. Because growth capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from such financing until the earlier to occur of the date any such capital asset begins producing in paying quantities or is placed into service, as applicable, and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

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

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4125 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Expiration of the Subordination Period

The subordination period will end on the earlier of:


	•	the later to occur of (a) the second anniversary of the closing of this offering and (b) such time 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.

Effect of the Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. Also, from and after the expiration of the subordination period, our general partner will have the right under our partnership agreement to convert a portion of its management incentive fee into Class B units under certain circumstances. Please read “— General Partner’s Right to Convert Management Incentive Fee into Class B Units” on page 101 for more information about such conversion right.

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

If the unitholders remove our general partner other than for cause and no units held by the holders of the subordinated units or their affiliates are voted in favor of such removal:


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

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

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

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each 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 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 unitholders and subordinated unitholders, pro rata, and 0.1% to our general partner.

The preceding discussion is based on the assumptions that we do not issue any additional classes of equity securities and that our general partner maintains its 0.1% general partner interest in us.

Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus 99.9% to the common unitholders and Class B unitholders, if any, pro rata, and 0.1% to our general partner for any quarter after the subordination period, assuming that our general partner maintains it 0.1% general partner interest and we do not issue additional classes of equity securities.

General Partner Interest and Management Incentive Fee

Our partnership agreement provides that our general partner initially will be entitled to 0.1% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for general partner units to maintain its 0.1% general partner interest if we issue additional units. Our general partner’s 0.1% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future (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 Class B units in connection with a conversion of the management incentive fee, 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 to maintain its 0.1% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash, and our general partner may fund its capital contribution by the contribution to us of common units or other property.

Under our partnership agreement, for each quarter for which we have paid cash distributions that equaled or exceeded our Target Distribution, our general partner will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of the Gross Management Incentive Fee Base, or if a Conversion Election has previously been made, the Adjusted Management Incentive Fee Base (as described below). No portion of the management incentive fee determined for any calendar quarter will be due 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 the payment of such management incentive fee would have caused adjusted operating surplus (which is described below and in the glossary included as Appendix B) generated during such quarter to be less than 100% of our quarterly distribution paid (or set aside for payment) for such quarter on all outstanding common, subordinated and general partner units and Class B units, if any, as if such management incentive fee had been paid in such quarter. 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.

The Gross Management Incentive Fee Base 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.

If no agreement is reached, an independent investment banking firm or other independent expert selected by our general partner and the conflicts committee will determine the fair market value. If our general partner and the conflicts committee cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

100

Each of the Gross Management Incentive Fee Base and, following the initial Conversion Election as described “— General Partner’s Right to Convert Management Incentive Fee into Class B Units” on page 101, the Adjusted Management Incentive Fee Base, will be calculated (each, a “Calculation Date”) 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 the management incentive fee is due.

Adjusted Operating Surplus

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


	•	operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “— Operating Surplus and Capital Surplus — Operating Surplus” on page 95); less

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

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

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

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

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

General Partner’s Right to Convert Management Incentive Fee into Class B Units

General

From and after the end of the subordination period and subject to the limitations described below, 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 full 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%, such percentage actually converted being referred to as the Applicable Conversion Percentage, of the management incentive fee for the fourth quarter in lieu of receiving a cash payment for such portion of the management incentive fee. Any Conversion Election made during a quarter must be made before payment of the management incentive fee in respect of the previous quarter and will be effective as of the first day of such quarter, and the Class B units issued upon such conversion will be entitled to distributions as if they were outstanding on the first day of such quarter.

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 Conversion Percentage; 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.

101

We refer to such conversion as a “Conversion Election.” 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 the event of such Conversion Election, unless we experience a change of control, our general partner will not be permitted to exercise the Conversion Election again until (i) the completion of the fourth full calendar quarter following the previous Conversion Election and (ii) the Gross Management Incentive Fee Base has increased to 115% of the Gross Management Incentive Fee Base as of the immediately preceding conversion date.

Initial Conversion Election

Immediately following the initial Conversion Election, the Adjusted Management Incentive Fee Base, until the next Calculation Date, will equal the product of (i) the Gross Management Incentive Fee Base then in effect and (ii) one minus the Applicable Conversion Percentage. Prior to the initial Conversion Election, the Adjusted Management Incentive Fee Base will equal the Gross Management Incentive Fee Base.

First Calculation Date Following Initial Conversion Election

As of the first Calculation Date following the initial Conversion Election, the Adjusted Management Incentive Fee Base will equal the sum of:


	•	the product of (x) one minus the initial Applicable Conversion Percentage and (y) the Gross Management Incentive Fee Base in effect at the time of the initial Conversion Election; and

	•	the Gross Management Incentive Fee Base as in effect on the current Calculation Date less the Gross Management Incentive Fee Base in effect at the time of the initial Conversion Election.

Subsequent Conversion Elections

As of the second and each subsequent Conversion Election, the Adjusted Management Incentive Fee Base will equal the product of (x) one minus the Applicable Conversion Percentage for such Conversion Election and (y) the Adjusted Management Incentive Fee Base in effect immediately prior to such Conversion Election.

Subsequent Calculation Dates

As of the second and each subsequent Calculation Date following the initial Conversion Election, the Adjusted Management Incentive Fee Base will equal the sum of:


	•	the product of (x) one minus the most recent Applicable Conversion Percentage and (y) the Adjusted Management Incentive Fee Base in effect immediately prior to the most recent Conversion Election; and

	•	the Gross Management Incentive Fee Base as in effect on the current Calculation Date less the Gross Management Incentive Fee Base as in effect on the Calculation Date immediately preceding the most recent Conversion Election.

Hypothetical Management Incentive Fee and Conversion Calculations

The discussion below is a hypothetical scenario illustrating potential management incentive fee payments to our general partner under the terms of our partnership agreement, together with the hypothetical impact of multiple Conversion Elections by our general partner and the effect on both our general partner and holders of our common units. For purposes of this discussion, we have made the following assumptions:


	•	the subordination period has expired;

	•	a Target Distribution of $0.4744 per unit, or $1.90 per unit on an annualized basis;

102


	•	for each of the quarters ending June 30, 2012, September 30, 2012 and December 31, 2012, we pay a distribution equal to the Target Distribution, and our general partner receives (or we reserve for payment) at least a portion of the management incentive fee for each such quarter;

	•	for each of the quarters ending June 30, 2012, September 30, 2012 and December 31, 2012, we have sufficient operating surplus to pay each of the Target Distribution and the portion of the management incentive fee paid in respect of that quarter;

	•	our Gross Management Incentive Fee Base is set at $500,000,000 as of June 30, 2011 and remains constant thereafter, other than the increases described below;

	•	our general partner does not own any common units or convert any Class B units into common units (and we ignore our general partner’s general partner units); and

	•	no prior Conversion Elections have been made.

Please note that this hypothetical scenario is intended for illustrative purposes only. We can give you no assurance that any payment of the management incentive fee or any conversion will occur in the manner described below. There will likely be differences between the hypothetical scenario presented below and any payment of the management incentive fee or any conversion, and those differences could be material.

Initial Conversion. For the quarter ending March 31, 2013, we pay a distribution of $0.4744 per unit, or the Target Distribution. As a result of our paying distributions that equaled or exceeded the Target Distribution, our general partner would be entitled to receive the management incentive fee of 0.25% of the Gross Management Incentive Fee Base of $500,000,000, or $1,250,000.

Based on the assumptions that our general partner will have received all or a portion of the management incentive fee in respect of three consecutive quarters and shall be entitled to receive all or a portion of the management incentive fee for a fourth consecutive quarter and that the subordination period will have ended, our general partner will have the right to make a Conversion Election. If our general partner elects to convert 80% of the management incentive fee in respect of the quarter ending March 31, 2013 into Class B units, then the following would result:

March 31, 2013

Issuance of Class B Units

Applicable

Most Recent

Remaining

Management

Conversion

Quarterly

Class B Units

Management

Incentive Fee(1)

Percentage

Distribution

Issued(2)

Incentive Fee(3)

$1,250,000

0.4744

2,107,926

250,000


(1)		Represents the average of the management incentive fee paid or payable to our general partner in respect of the immediately prior two calendar quarters, which has been held constant for the purposes of this illustration.

(2)		The product of the Applicable Conversion Percentage of 80% and $1,250,000, or $1,000,000, is converted into a number of Class B units to equate to $1,000,000 of unit distributions, or 2,107,926 Class B units based on our most recent quarterly distribution per common unit.

(3)		Our general partner would be entitled to receive the remaining, unconverted portion of the management incentive fee in cash.

The Class B Units issued upon such conversion will be entitled to distributions as if they were outstanding on the first day of such quarter. In addition, the Class B units would be immediately convertible into common units at the election of our general partner.

Adjusted Management Incentive Fee Base Following Initial Conversion Election. Following this hypothetical initial Conversion Election, the Adjusted Management Incentive Fee Base would be set at $100,000,000, which represents an 80% (the Applicable Conversion Percentage) reduction from the Gross Management Incentive Fee Base of $500,000,000.

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Subsequent Management Incentive Fees. For the quarter ending June 30, 2013, we pay a distribution of $0.4744 per unit, equal to the Target Distribution. As a result, our general partner would be entitled to receive a management incentive fee of 0.25% of $100,000,000 (the Adjusted Management Incentive Fee Base), or $250,000, for this quarter. In addition to the management incentive fee, our general partner would also receive aggregate distributions with respect to its Class B units of $1,000,000 for this quarter. Based on the reduction of the management incentive fee of $1,000,000 per quarter and the increase in distributions with respect to Class B units aggregating $1,000,000 per quarter, the common unit holders receive the same per unit distribution of $0.4744 as would have been received prior to the conversion.

If these assumptions remained constant for all future quarters, cash received by our general partner each quarter would be equal to a management incentive fee of $250,000 and $1,000,000 in distributions from its Class B units, or an aggregate amount equal to 0.25% of the Gross Management Incentive Fee Base of $500,000,000. Common unit holders would receive $0.4744 per unit per quarter, equal to the amount they would have otherwise received without any conversion of the management incentive fee.

Increase in Adjusted Management Incentive Fee Base. For the purposes of this example, assume that based on our reserve estimates as of June 30, 2013, our Gross Management Incentive Fee Base is increased to $600,000,000. This increase could have resulted from a number of factors, including any combination of acquisitions of additional oil and natural gas properties from a third party or from the Fund or favorable changes in commodity prices beyond our hedged volumes used in our standard measure calculation. As a result of the $100,000,000 increase in the Gross Management Incentive Fee Base to $600,000,000, the Adjusted Management Incentive Fee Base would likewise be increased to $200,000,000, which is the sum of $100,000,000 (the previous Adjusted Gross Management Incentive Fee Base) plus the $100,000,000 increase in the Gross Management Incentive Fee Base (the excess of the Gross Management Incentive Fee Base as of the June 30, 2013 Calculation Date ($600,000,000) over the Gross Management Incentive Fee Base at the time of the initial Conversion Election ($500,000,000)).

Subsequent Management Incentive Fees. For the quarter ended December 31, 2013, we pay a distribution of $0.4744 per unit, equal to the Target Distribution. As a result, our general partner would be entitled to receive a management incentive fee of 0.25% of $200,000,000 (the then-applicable Adjusted Management Incentive Fee Base), or $500,000, for this quarter. In addition to the management incentive fee, our general partner would also receive aggregate distributions with respect to its Class B units of $1,000,000 for this quarter.

If these assumptions remained constant for all future quarters, cash received by our general partner each quarter would be equal to a management incentive fee of $500,000 and $1,000,000 in distributions from its Class B units, or 0.25% of the Gross Management Incentive Fee Base of $600,000,000. Common unit holders would receive $0.4744 per unit per quarter, equal to the amount they would have otherwise received prior to any conversion of the management incentive fee.

Subsequent Conversion. For the quarter ending March 31, 2014, we pay a distribution of $0.4744 per unit, equal to the Target Distribution. Because (i) it has now been four calendar quarters since the immediately preceding Conversion Election and (ii) the Gross Management Incentive Fee Base shall have increased to more than 115% of its value immediately following the immediately preceding Conversion Election (from $500,000,000 to $600,000,000, an increase to 120%), our general partner will have the right to make a subsequent Conversion Election in respect of the quarter ended March 31, 2014. Based on this hypothetical, this would be the earliest quarter in respect of which our general partner would be eligible to make such a subsequent Conversion Election. If our general partner elects to convert 80% of the management incentive fee into Class B units, then the following would result:

March 31, 2014

Issuance of Class B Units

Applicable

Most Recent

Remaining

Management

Conversion

Quarterly

Class B Units

Management

Incentive Fee(1)

Percentage

Distribution

Issued(2)

Incentive Fee(3)

$500,000

0.4744

843,170

100,000

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(1)		Represents the average of the management incentive fee paid or payable to our general partner in respect of the immediately prior two calendar quarters, which has been held constant for the purposes of this illustration.

(2)		The product of the Applicable Conversion Percentage of 80% and $500,000, or $400,000, is converted into a number of Class B units to equate to $400,000 of unit distributions, or 843,170 Class B units based on our most recent quarterly distribution per common unit.

(3)		Our general partner would be entitled to receive the remaining, unconverted portion of the management incentive fee in cash.

Adjusted Management Incentive Fee Base Following Subsequent Conversion Election. Following this hypothetical subsequent Conversion Election, the Adjusted Management Incentive Fee Base would be set at $40,000,000, which represents an 80% (the Applicable Conversion Percentage) reduction from the pre-conversion Adjusted Management Incentive Fee Base of $200,000,000.

Future Management Incentive Fees. For any subsequent quarterly distributions paid at or above the Target Distribution level, our general partner would be entitled to a management incentive fee of 0.25% of the Adjusted Management Incentive Fee Base of $40,000,000, or $100,000. In addition to the management incentive fee, our general partner would also receive aggregate distributions of $1,400,000 with respect to the 2,951,095 Class B units that it owned. Based on the reduction of the management incentive fee of $400,000 per quarter and the increase in distributions with respect to its additional 2,951,095 Class B units of $400,000 per quarter, the common unit holders receive the same per unit distribution of $0.4744 per quarter as would have been received prior to the conversion.

If these assumptions remained constant for all future quarters, cash received by our general partner per quarter would be equal to a management incentive fee of $100,000 and $1,400,000 in distributions from its Class B units, or an aggregate amount equal to 0.25% of the-then applicable Gross Management Incentive Fee Base of $600,000,000. Common unit holders would receive $0.4744 per unit per quarter, equal to the amount they would have otherwise received prior to any conversion of the management incentive fee.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

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


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

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

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

The preceding discussion is based on the assumption that our general partner maintains its 0.1% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, similar to a return of capital. Each time a distribution of

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capital surplus is made, the minimum quarterly distribution and the Target Distribution will be reduced in the same proportion as the distribution had in relation to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and Target Distribution, after any of these distributions are made, it may be easier for our general partner to receive a management incentive fee in a particular quarter. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

If we reduce the minimum quarterly distribution to zero, we will then make all future distributions as if they were from operating surplus, with 99.9% being distributed to the holders of our common, Class B and subordinated units, pro rata, and 0.1% being distributed to our general partner. For a discussion of the risk related to a distribution from capital surplus, please read “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.

Adjustment to the Minimum Quarterly Distribution and Target Distribution

In addition to adjusting the minimum quarterly distribution and Target Distribution to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, we will proportionately adjust:


	•	the minimum quarterly distribution;

	•	the Target Distribution;

	•	the unrecovered initial unit price, as described below; and

	•	the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the Target Distribution and the unrecovered initial unit price would each be reduced to 50% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units and general partner units using the same ratio applied to the common units.

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

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to our unitholders and our general partner, in

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accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units and Class B units upon our liquidation, to the extent required to permit common unitholders to receive the price paid for the common units issued in this offering, less any prior distributions of capital surplus in respect of common units issued in this offering, which we refer to as the “unrecovered initial unit price,” plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units.

Manner of Adjustments for Gain

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


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

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

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

	•	*Thereafter*, 99.9% to all unitholders, pro rata, and 0.1% to our general partner.

If our liquidation occurs after the end of the subordination period, we will allocate any gain to the partners in the following manner:


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

	•	*Second*, 99.9% to the Class B unitholders, if any, pro rata, and 0.1% to our general partner until the capital account for each Class B unit is equal to the per unit capital account of a common unit; and

	•	*Thereafter*, 99.9% to all unitholders, pro rata, and 0.1% to our general partner.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and the unitholders in the following manner:


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

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

	•	*Thereafter*, 100% to our general partner.

If our liquidation occurs after the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will allocate any loss to the partners in the following manner:


	•	*First*, 99.9% to holders of common units in proportion to the positive balances in their capital accounts and 0.1% to our general partner, until the per unit capital account for a common unit equals the per unit capital account for a Class B unit;

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

	•	*Thereafter*, 100% to our general partner.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for U.S. federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table shows selected historical financial data of our predecessor and pro forma financial information of QR Energy, LP. Due to the factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview” beginning on page 112 our future results of operations will not be comparable to the historical results of our predecessor. The selected historical 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 selected historical financial data as of December 31, 2005, 2006 and 2007 and for the year ended December 31, 2005, for the period from January 1, 2006 to September 7, 2006 and for the period from April 1, 2006 to December 31, 2006 are derived from audited historical consolidated financial statements not included herein. The summary historical 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 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 million in cash including $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 “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

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things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.


	Our Predecessor Properties						Our Predecessor
							For the																		QR Energy, LP
				For the Period			Period from																		Pro Forma
				from January 1,			April 1,																					Nine Months
	Year Ended			2006 to			2006 to																		Year Ended			Ended
	December 31,			September 7,			December 31,			Year Ended December 31,									Nine Months Ended September 30,						December 31,			September 30,
	2005			2006			2006			2007			2008			2009			2009			2010			2009			2010
	(in thousands)

Revenues:
Gas, oil, natural gas liquids and sulfur sales	$	59,641		$	38,744		$	17,886		$	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	$	59,641		$	38,744		$	17,886		$	171,317		$	281,070		$	72,801		$	53,078		$	175,470		$	76,904		$	74,308

Operating costs and expenses:
Lease operating	$	12,716		$	9,540		$	6,604		$	77,767		$	90,424		$	33,328		$	23,724		$	52,152		$	23,783		$	15,242
Production taxes		3,831			2,737			1,553			12,954			14,566			7,587			4,975			12,528			5,764			3,325
Transportation and processing costs		—			—			177			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		5,781			3,299			5,579			42,889			49,309			16,993			13,743			45,149			24,400			18,316
Accretion of asset retirement obligations		304			200			119			2,751			3,004			3,585			2,847			2,648			827			822
Fund management fees(2)		—			—			6,895			11,482			12,018			12,018			9,013			7,885			—			—
Acquisition evaluation costs		—			—			—			—			—			—			7			1,197			—			—
General and administrative and other		1,127			906			6,380			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	$	23,759		$	16,682		$	27,307		$	173,248		$	661,802		$	124,036		$	97,318		$	144,835		$	81,488		$	50,971

Income (loss) from operations	$	35,882		$	22,062		$	(9,421	)	$	(1,931	)	$	(380,732	)	$	(51,235	)	$	(44,240	)	$	30,635		$	(4,584	)	$	23,337

Other income (expenses):
Interest income	$	—		$	—		$	278		$	978		$	617		$	37		$	32		$	27		$	—		$	—
Realized gains (losses) on commodity derivative contracts		(25,002	)		(29,328	)		3,522			6,861			(34,666	)		47,993			42,177			5,132			23,595			2,093
Unrealized gains (losses) on commodity derivative contracts		(1,117	)		—			38,301			(157,250	)		169,321			(111,113	)		(74,123	)		41,432			(54,628	)		16,894
Interest expense		—			—			(3,135	)		(17,359	)		(13,034	)		(3,753	)		(2,939	)		(31,392	)		(7,770	)		(5,827	)
Other		—			(207	)		—			7			(10,039	)		2,657			2,240			5,147			—			—

Total other income (expense)		(26,119	)		(29,535	)		38,966		$	(166,763	)	$	112,199			(64,179	)	$	(32,613	)	$	20,346		$	(38,803	)	$	13,160

Net income (loss)	$	9,763		$	(7,473	)	$	29,545		$	(168,694	)	$	(268,533	)	$	(115,414	)	$	(76,853	)	$	50,981		$	(43,387	)	$	36,497

Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	15,995		$	(6,478	)	$	(1,460	)	$	24,839		$	75,282		$	64,907		$	44,560		$	50,762
Investing activities		(4,838	)		(1,690	)		(500,313	)		(72,953	)		(137,161	)		(55,458	)		(41,321	)		(931,044	)
Financing activities		(11,157	)		8,168			512,671			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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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This Management’s Discussion and Analysis of Financial Condition and Results of Operations contains the following information:


	•	a discussion of our business on a pro forma basis, including:


	•	a general overview of our properties;

	•	our results of operations;

	•	our liquidity and capital resources; and

	•	our quantitative and qualitative disclosures about market risk; and


	•	a discussion of our predecessor’s business on a historical basis, including:


	•	our predecessor’s results of operations;

	•	our predecessor’s liquidity and capital resources; and

	•	our predecessor’s quantitative and qualitative disclosures about market risk.

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the “Selected Historical and Pro Forma Financial Data” beginning on page 109 and the accompanying financial statements and related notes included elsewhere in this prospectus. Unless otherwise indicated, all references to financial or operating data on a pro forma basis give effect to the transactions described under “Prospectus Summary — Formation Transactions and Partnership Structure” on page 8 and in the Unaudited Pro Forma Condensed Financial Statements included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” beginning on page 29 and “Forward-Looking Statements” on page 250, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are a Delaware limited partnership formed in September 2010 by affiliates of the Fund to own and acquire producing oil and natural gas properties in North America. Upon completion of this offering, the Fund will contribute to us (1) certain oil and natural gas properties and an 8.05% overriding oil royalty interest in the Jay Field, which we refer to as the Partnership Properties and (2) commodity derivative contracts covering approximately 47% to 80% of our estimated oil and natural gas production through 2015, based on production estimates in our reserve report dated June 30, 2010.

Our Properties

Following the contribution of the Partnership Properties to us, we will own and operate oil and natural gas producing properties located in Alabama, Arkansas, Kansas, Louisiana, New Mexico, Oklahoma and Texas, and a 8.05% overriding oil royalty interest in the Jay Field located in Florida. These properties consist of working interests in 2,099 gross (534 net) producing wells, of which we owned an approximate 25% average working interest. Based on standardized measure, however, our value-weighted-average working interest on the Partnership Properties was approximately 68%. As of June 30, 2010, our total estimated proved reserves were approximately 29.7 MMBoe, of which

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approximately 69% were oil and NGLs and 68% were classified as proved developed reserves. As of June 30, 2010, our estimated proved reserves had standardized measure of $467.3 million. Based on our average pro forma net production for the nine months ended September 30, 2010 of 5,184 Boe/d, the total estimated proved reserves associated with the Partnership Properties on a pro forma basis had a reserve-to-production ratio of 15.7 years.

Of our total estimated proved reserves as of June 30, 2010, 17.8 MMBoe, or approximately 60%, are located in the Permian Basin; 7.9 MMBoe, or approximately 27%, are located in the Ark-La-Tex area; 2.2 MMBoe, or approximately 7%, are located in the Mid-Continent area; and 1.8 MMBoe, or approximately 6%, are located in the Gulf Coast area, primarily the Jay Field. On a pro forma basis, our total estimated proved reserves represented approximately 34% of our predecessor’s total estimated proved reserves as of June 30, 2010.

Retained 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% is classified as proved developed reserves, with a 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 net production of approximately 13,132 Boe/d for the nine months ended September 30, 2010. The Fund’s retained assets will consist of legacy properties in our producing regions with characteristics similar to the Partnership Properties. 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.

How We Conduct Our Business and Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:


	•	production volumes;

	•	realized prices on the sale of oil and natural gas, including the effect of our commodity derivative contracts;

	•	production expenses and general and administrative expenses; and

	•	Adjusted EBITDA.

Production Volumes

Production volumes directly impact our results of operations. For more information about our predecessor’s and our pro forma production volumes, please read “— Historical Pro Forma Financial and Operating Data.”

Realized Prices on the Sale of Oil and Natural Gas

Factors Affecting the Sales Price of Oil and Natural Gas. We will market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.

Oil Prices. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products.

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Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil’s American Petroleum Institute, or API, gravity and (2) the oil’s percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value, and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil (“sour” oil).

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the produced oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).

The oil produced from our properties is a combination of sweet and sour oil, varying by location. We sell our oil at the NYMEX-WTI price, which is adjusted for quality and transportation differential, depending primarily on location and purchaser. The differential varies, but our oil normally sells at a discount to the NYMEX-WTI price.

Natural Gas. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO₂ and other inert content by volume. Wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO₂ content sells at a premium to natural gas with high sulfur and CO₂ content because of the added cost to separate the sulfur and CO₂ from the natural gas to render it marketable. The wet natural gas is processed in third-party natural gas plants and residue natural gas as well as NGLs are recovered and sold. The majority of the Partnership Properties produce wet gas. Our wellhead Btu has an average energy content greater than 1100 Btu and minimal sulfur and CO₂ content and generally receives a premium valuation. The dry natural gas residue from our Partnership Properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds. Generally, these index prices have historically been at a discount to NYMEX-Henry Hub natural gas prices.

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.

Commodity Derivative Contracts. 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

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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. These instruments limit our exposure to declines in prices, but also limit the benefits if prices increase. We do not specifically designate commodity derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these contracts is recorded in current period earnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Realized gains or losses only arise from payments made or received on monthly settlements or if a commodity derivative contracts is terminated prior to its expiration. Please read “— Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts” on page 124.

At the closing of this offering, the Fund intends to contribute to us, in conjunction with contributing assets, certain 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. Please read “— Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts” on page 124. The following table reflects, with respect to these commodity derivative contracts to be provided to us, the volumes of our production covered by commodity derivative contracts and the average prices at which the production will be hedged:


	Year Ending December 31,
	2011		2012		2013		2014		2015

Oil Derivative Contracts:
Swap contracts:
Volume (Bbls/d)		2,238		2,039		2,076		2,090		2,000
Average NYMEX-WTI price per Bbl	$	85.00	$	85.25	$	85.35	$	84.58	$	87.40
Natural Gas Derivative Contracts:
Swap contracts:
Volume (MMBtu/d)		9,178		8,192		7,474		7,544		3,398
Average NYMEX-Henry Hub price per MMBtu	$	7.26	$	6.45	$	6.45	$	6.30	$	5.52

Production Expenses and General and Administrative Expenses

Production Expenses. We strive to increase our production levels to maximize our revenue and cash available for distribution. Production expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our production expenses. Production expenses do not include general and administrative costs. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased production expenses in periods during which they are performed.

A majority of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production related activities such as pumping to recover oil and natural gas, separation and treatment of water produced in connection with our oil and natural gas production, and re-injection of water and gas into the oil producing formation to maintain reservoir pressure. As these costs are driven not only by volumes of oil produced but also volumes of water produced, fields that have a high percentage of water production relative to oil production, also known as a high water cut, will experience higher levels of power costs for each Bbl of oil produced. A majority of our oil is produced from fields undergoing a secondary recovery technique known as a waterflood in which water is reinjected into the formation. Over the life of these fields, the amount of water produced increases for

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a given volume of oil production. Thus production of a given Bbl of oil gets more expensive each year as the cumulative oil produced from a field increases until, at some point, additional production becomes uneconomic. We believe that one of management’s areas of core expertise lies in reducing these expenses, thus extending the economic life of the field and improving the cash margin of producing oil associated with a high water cut.

Additionally, we monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we monitor our production expenses and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold. We typically evaluate our oil and natural gas operating costs on a per Boe basis. This unit rate allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers.

General and Administrative Expenses. 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. Thereafter, our general partner will be required to reimburse Quantum Resources Management in full for the general and administrative expenses incurred or allocated to us by Quantum Resources Management in the performance of the services agreement. For the year ending December 31, 2011, we expect the administrative services fee will be approximately $3.1 million. Our total general and administrative expenses will include our direct general and administrative costs as well as an estimate of the relative portion of our indirect overhead costs incurred by the Fund. We will record the portion of total general and administrative expenses in excess of the administrative services fee as a capital contribution by the Fund and have therefore added back such portion in the calculation of Adjusted EBITDA. For a detailed description of the administrative services fee paid to Quantum Resources Management pursuant to the services agreement, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement” on page 188.

Adjusted EBITDA

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.

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	•	Less:


	•	Interest income; and

	•	Unrealized gains on commodity derivative contracts.

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 unitholders, develop existing reserves or acquire additional oil and natural gas properties. We also use Adjusted EBITDA to calculate the administrative services fee our general partner pays to Quantum Resources Management under the services agreement. 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 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. For further discussion, please read “Prospectus Summary — Non-GAAP Financial Measures” on page 25.

Impact of the Jay Field Shut-In

Production from the Jay Field was temporarily suspended from December 2008 through November 2009, during which time the field and related facility were modified to increase runtime and improve cost performance. This temporary suspension had a material impact on the comparability of our predecessor’s period-to-period comparisons as there were limited production revenues from the Jay Field in 2009 to offset the fixed expenses relating to those operations. Since resuming production in December 2009, production from the Jay Field has increased, and is approaching average net production prior to being shut in. Average lifting costs have been substantially decreased by the modifications made during 2009, from approximately $55 per Boe at the time of suspension in late 2008 to approximately $33 per Boe from the field’s restart through September 30, 2010. The temporary suspension also affects the comparability of the historical financial statements of our predecessor for the year ended December 31, 2009 and the nine months ended September 30, 2009 to our pro forma operating results for such periods, as production and revenues from the Jay Field were more significant to our predecessor’s operations than they are to our pro forma results of operations. Our interest in the Jay Field consists solely of an 8.05% overriding royalty interest on oil production from our predecessor’s interests in the Jay Field, which represents 6% of our total estimated production for 2011.

Outlook

Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy demand. During this same period, North American natural gas supply was increasing as a result of the rise in domestic unconventional natural gas production. The combination of lower energy demand due to the economic slowdown and higher North American natural gas supply resulted in significant declines in oil, NGL and natural gas prices. While oil and NGL prices started to steadily increase beginning in the second quarter of 2009, natural gas prices remained volatile throughout 2009 and have remained low in 2010, relative to much of 2007, 2008 and 2009, due to a continued increase in natural gas supply despite weaker offsetting demand growth. The outlook for a worldwide economic recovery in 2011 remains uncertain, and the timing of a recovery in worldwide demand for energy is difficult to

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predict. As a result, it is likely that commodity prices will continue to be volatile during 2011 and 2012. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

As an oil and natural gas company, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. We attempt to overcome this natural decline by utilizing multiple types of recovery techniques, such as secondary (water injection) and tertiary (nitrogen and/or CO₂ injection) recovery methods, to repressure the reservoir in an effort to recover additional oil, drilling to find additional estimated reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add estimated reserves in excess of our production. We plan to maintain our focus on adding reserves through acquisitions and exploitation projects and improving the economics of producing oil and natural gas from our existing fields in lieu of higher-risk exploration projects. We expect that these acquisition opportunities may come from the Fund, Quantum Energy Partners and their respective affiliates as well as from unrelated third parties. Our ability to add estimated reserves through acquisitions and exploitation projects is dependent upon many factors, including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

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Historical and Pro Forma Financial and Operating Data

The following table sets forth selected historical consolidated financial and operating data of our predecessor and unaudited pro forma financial and operating data for QR Energy, LP for the periods presented. The following table should be read in conjunction with “Selected Historical and Pro Forma Financial Data” beginning on page 109.


														QR Energy, LP
	Our Predecessor													Pro Forma
									Nine Months					Year Ended		Nine Months Ended
	Year Ended December 31,								Ended September 30,					December 31,		September 30,
	2007			2008			2009		2009		2010			2009		2009		2010

Revenues (in thousands):
Oil sales	$	119,978		$	170,716		$	41,188	$	28,670	$	112,972		$	52,524	$	36,025	$	51,224
Natural gas sales		37,305			53,755			21,592		16,179		45,800			19,800		14,336		17,882
NGLs sales		6,086			8,994			7,043		4,715		9,744			4,580		2,987		5,202
Processing fees, sulfur sales and other		7,948			47,605			2,978		3,514		6,954			—		—		—

Total Revenue	$	171,317		$	281,070		$	72,801	$	53,078	$	175,470		$	76,904	$	53,348	$	74,308

Expenses (in thousands):
Lease operating expenses	$	77,767		$	90,424		$	33,328	$	23,724	$	52,152		$	23,783	$	16,891	$	15,242
Production and other taxes		12,954			14,566			7,587		4,975		12,528			5,764		2,882		3,325
Fund management fees		11,482			12,018			12,018		9,013		7,885			—		—		—
General and administrative and other		20,677			14,852			19,461		12,916		19,400			11,268		9,776		12,329
Depletion, depreciation and amortization		42,889			49,309			16,993		13,743		45,149			24,400		18,316		18,316
Production:
Oil (MBbls)		1,668			1,753			739		566		1,573			931		700		689
Natural gas (MMcf)		5,476			5,590			5,359		4,096		10,122			5,151		3,907		3,687
NGLs (MBbls)		121			139			207		152		228			137		101		111
Total (MBoe)		2,701			2,824			1,838		1,401		3,488			1,927		1,452		1,415
Average net production (Boe/d)		7,401			7,736			5,038		5,133		12,742			5,280		5,319		5,184
Average sales price:
Oil (per Bbl):
Sales price	$	71.94		$	97.40		$	55.74	$	50.56	$	71.82		$	56.41	$	51.46	$	74.35
Effect of realized commodity derivative contracts(1)		(0.83	)		(20.02	)		38.73		48.84		(3.02	)

Realized price	$	71.11		$	77.38		$	94.47	$	99.40	$	68.80
Natural gas (per Mcf):
Sales price	$	6.81		$	9.62		$	4.03	$	3.95	$	4.52		$	3.84	$	3.67	$	4.85
Effect of realized commodity derivative contracts(1)		1.51			0.07			3.61		3.55		0.98

Realized price	$	8.32		$	9.69		$	7.64	$	7.50	$	5.50
NGLs (Per Bbl)	$	50.29		$	64.70		$	34.02	$	31.02	$	42.74		$	33.31	$	29.57	$	46.86
Average unit costs per Boe:
Lease operating expenses	$	28.79		$	32.02		$	18.13	$	16.93	$	14.95		$	12.34	$	11.63	$	10.77
Production and other taxes	$	4.80		$	5.16		$	4.13	$	3.55	$	3.59		$	2.99	$	1.98	$	2.35
Management fees	$	4.25		$	4.26		$	6.54	$	6.43	$	2.26			—		—		—
General and administrative and other	$	7.66		$	5.26		$	10.59	$	9.22	$	5.56		$	5.85	$	6.73	$	8.71
Depletion, depreciation and amortization	$	15.88		$	17.46		$	9.24	$	9.81	$	12.94		$	12.66	$	12.63	$	12.96


(1)		Realized gains (losses) on commodity derivative contracts were $2.54, $(12.28), $26.11, $30.10 and $1.48 per Boe, respectively, for the years ended December 31, 2007, 2008 and 2009 and the nine months ended September 30, 2009 and 2010. Pro forma average sales 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. Accordingly, we have omitted the effects of commodity derivative contracts from our pro forma average sales prices per Boe.

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Pro Forma Results of Operations

The discussion of the results of operations presented below covers our pro forma results of operations. These pro forma results may not be indicative of future results or of actual historical results had the Partnership Properties been contributed to us on January 1, 2009. Please read “Selected Historical and Pro Forma Financial Data” beginning on page 109 for financial information relating to us as of the dates and for the periods presented.

Factors Affecting the Comparability of the Pro Forma Results of Our Partnership to the Historical Financial Results of Our Predecessor

Our pro forma results of operations and our future results of operations may not be comparable to the historical results of operations of our predecessor for the periods presented, primarily for the reasons described below:


	•	Approximately 34% of our predecessor’s total estimated proved reserves as of June 30, 2010 will be contributed to us at the closing of this offering. Accordingly, the historical results of operations of our predecessor reflect a larger business for certain periods than the properties contributed to us.

	•	Our predecessor completed the Denbury Acquisition in May 2010. Prior to such time, the estimated proved reserves associated with and the results of operations from the Denbury Assets were not included in our predecessor’s results of operations. Certain of the Denbury Assets are included in the Partnership Properties that will be contributed to us at the closing of this offering. They will represent a significant portion of the Partnership Properties, and represent approximately 58% of our total estimated proved reserves as of June 30, 2010.

	•	Our predecessor pays a management fee to its general partner pursuant to its partnership agreement. We are not obligated to pay such a management fee, and so our pro forma results of operations are not directly comparable to our predecessor’s with respect to this fee. The management incentive fee we will pay is distinct from, but analogous to, the management fee that our predecessor paid to its general partner.

	•	Our predecessor uses commodity derivative contracts to manage price fluctuations and will contribute certain commodity derivative contracts to us upon closing of this offering. Our pro forma results of operations for the year ended December 31, 2009 and the nine months ended September 30, 2009 and 2010 reflect the estimated impact of any commodity derivative contracts as if we had acquired them on January 1, 2009.

	•	Our predecessor’s results of operations were adversely impacted for the full year 2009 as a result of shutting in production from the Jay Field in late 2008. Our predecessor incurred significant capital expenditures to modify the field and related facilities to increase runtime and improve cost performance and did not resume production from the Jay Field until December 2009. The historical financial statements of our predecessor for the year ended December 31, 2009 and the nine months ended September 30, 2009 may not be comparable to our pro forma operating results for such periods, as the production and revenues from the Jay Field were more significant to our predecessor’s operations than they are to our pro forma results of operations. We have an 8.05% overriding royalty interest, which is unencumbered by costs, on oil production from our predecessor’s interests in the Jay Field, which represents 6% of our total estimated production for 2011, whereas our predecessor derived more than 39% of its 2008 production from the Jay Field.

Pro Forma Results of Operations

Our net income for the nine months ended September 30, 2010 was $36.5 million as compared to a net loss of $31.7 million for the nine months ended September 30, 2009. The increase in net income was primarily attributable to increases in the average price realized on oil sales to $74.35 per Bbl from $51.46 per Bbl. The increase in net income was also attributable to movements in commodity derivative

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contracts and the absence of an impairment of our oil and natural gas properties in 2010. For the year ended December 31, 2009, we had a net loss of $43.4 million partially as a result of $54.6 million unrealized loss on commodity derivative instruments.

Sales Revenues. Sales revenues increased by $21.0 million to $74.3 million for the nine months ended September 30, 2010 as compared to sales revenues of $53.3 million for the nine months ended September 30, 2009. The increase in sales revenues was primarily attributable to higher sales prices received for our production, and was partially offset by a slight decrease in production during the period. In particular, our average sales price for oil increased from $51.46 per Bbl during the nine months ended September 30, 2009 to $74.35 per Bbl for the nine months ended September 30, 2010. Similarly, our average sales prices for natural gas increased from $3.67 per Mcf for the nine months ended September 30, 2009 to $4.85 per Mcf for the nine months ended September 30, 2010. Our average net production decreased from 5,319 Boe/d during the nine months ended September 30, 2009 to 5,184 Boe/d during the nine months ended September 30, 2010, primarily as a result of natural production declines, partially offset by increased production as a result of the restart of the Jay Field.

Our sales revenues for the year ended December 31, 2009 were $76.9 million. Our average sales prices for oil and natural gas for the year ended December 31, 2009 were $56.41 per Bbl and $3.84 per Mcf, respectively, and our average net production for the year ended December 31, 2009 was 5,280 Boe/d.

Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, we recorded a net gain from our commodity hedging program during the first nine months of 2010 of approximately $19.0 million, comprised of a realized gain of approximately $2.1 million and an unrealized gain of approximately $16.9 million as compared to a net loss of approximately $15.7 million for the first nine months of 2009, comprised of realized gain of approximately $20.7 million and an unrealized loss of $36.4 million.

For the year ended December 31, 2009, we recorded a net loss from our commodity hedging program of approximately $31.0 million, comprised of a realized gain of approximately $23.6 million and an unrealized loss of approximately $54.6 million.

These commodity derivative gains and losses reflect the allocation of historical realized and unrealized gains on losses on commodity derivative contracts contributed to us by our predecessor. The allocation was based on a percentage of the relative fair vale of the Partnership Properties that will be contributed to us by our predecessor.

Lease Operating Expenses. Lease operating expenses decreased slightly to $15.2 million for the nine months ended September 30, 2010 as compared to $16.9 million for the same period in 2009, as a result of decreased service costs. On a per Boe basis, our lease operating expenses decreased from $11.63 per Boe produced during the nine months ended September 30, 2009 to $10.77 per Boe produced during the nine months ended September 30, 2010 due to the decrease in service costs, partially offset by decreases in production. Generally, lease operating expenses are relatively stable due to the long-lived nature of the Partnership Properties.

Lease operating expenses for the year ended December 31, 2009 were $23.8 million, or $12.34 per Boe produced.

Production and Other Taxes. Production and other taxes increased from $2.9 million, or $1.98 per Boe, for the nine months ended September 30, 2009 to $3.3 million, or $2.35 per Boe produced, for the nine months ended September 30, 2010. The increase in the aggregate production taxes was attributable to the increase in revenue of $21.0 million. The increase in production taxes per Boe was due to an increase in sales prices, partially offset by a slight decrease in tax rates.

Production and other taxes for the year ended December 31, 2009 were $5.8 million, or $2.99 per Boe produced in 2009.

Depreciation, Depletion, and Amortization Expenses. Depreciation, depletion and amortization expenses for the nine months ended September 30, 2010 totaled $18.3 million, or $12.96 per Boe

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produced, as compared to $18.3 million, or $12.63 per Boe produced, for the nine months ended September 30, 2009. While depreciation, depletion and amortization expense has remained flat between periods, the per Boe increase was caused by the decrease in production described above.

Depreciation, depletion and amortization expenses for the year ended December 31, 2009 were $24.4 million, or $12.66 per Boe produced in 2009.

Impairment Expense. We recorded an impairment of $13.9 million under the full cost ceiling test during the nine months ended September 30, 2009 due to decline in prices in the first quarter of 2009. No impairment was required during the nine months ended September 30, 2010.

Impairment expense for the year ended December 31, 2009 was $13.9 million.

Fund Management Fee. Our predecessor has historically paid a management fee to the Fund in addition to its direct general and administrative expenses incurred. We will not be subject to this fund management fee following the formation transactions described in “Prospectus Summary — Formation Transactions and Partnership Structure” on page 8.

General and Administrative Expenses. Allocated general and administrative expenses for the nine months ended September 30, 2009 and 2010 were $9.8 million, or $6.73 per Boe produced, and $12.3 million, or $8.71 per Boe produced, respectively. This increase was primarily attributable to staff increases associated with our growth and transaction costs in the third quarter of 2010.

Allocated general and administrative expenses for the year ended December 31, 2009 were $11.3 million, or $5.85 per Boe produced.

Interest Expense. Interest expense for both the nine months ended September 30, 2009 and 2010 was $5.8 million, reflecting primarily interest expense from $225 million of borrowings under our new credit facility.

Interest expense for the year ended December 31, 2009 was $7.8 million.

Pro Forma Liquidity and Capital Resources

We expect that our primary sources of liquidity and capital resources after the consummation of the offering will be cash flows generated by operating activities and borrowings under the new credit facility that we intend to enter into concurrently with the closing of this offering. 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.

Capital Expenditures

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage). The primary purpose of maintenance capital is to maintain our production and asset base at a steady level over the long term to maintain our distributions per unit. For the twelve months ending December 31, 2011, we have estimated our maintenance capital expenditures to be $12.5 million.

Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The primary purpose of growth capital is to acquire producing assets that will

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increase our distributions per unit and secondarily increase the rate of development and production of our existing properties in a manner which is expected to be accretive to our unitholders. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. Although we may make acquisitions during the year ending December 31, 2011, including potential acquisitions of producing properties from the Fund, we have not estimated any growth capital expenditures related to acquisitions, as we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts.

The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our new credit facility will exceed our planned capital expenditures and other cash requirements for the twelve months ending December 31, 2011. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, generally. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.

New Credit Facility

Concurrently with the closing of this offering, we anticipate that our wholly owned subsidiary, QRE Operating, LLC, as borrower, and we and any other future domestic subsidiaries, as guarantors, will enter into a new credit facility, which we expect to be a five-year, $750 million revolving credit facility with an initial borrowing base of approximately $300 million.

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 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.

We anticipate that borrowings under the new credit facility will be secured by liens on at least 80% of our oil and natural gas properties and all of our equity interests in QRE Operating, LLC and any future guarantor subsidiaries. Additionally, we anticipate that borrowings under the new credit facility

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will bear interest, at our option, at either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee of 0.50% per annum.

The new credit facility will require maintenance of a ratio of Total Debt to EBITDAX (as each term is defined in the new credit facility), which we refer to as the leverage ratio, of not more than 4.0 to 1.0, and a current ratio of not less than 1.0 to 1.0. The definition of EBITDAX contained in the new credit facility is our Adjusted EBITDA, as defined in “Prospectus Summary — Non-GAAP Financial Measures” beginning on page 25, plus exploration expenses. However, because we account for our oil and natural gas exploration and development activities using the full cost method of accounting, we do not incur any exploration expenses, and thus our EBITDAX will be equivalent to our Adjusted EBITDA.

Additionally, the new credit facility will contain various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments (including a prohibition on our ability to pay distribution to our unitholders if our borrowing base usage exceeds 95%); modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. The new credit facility will also prohibit us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production from total proved reserves for the next two years and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in our most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments could be terminated and any outstanding indebtedness under the new credit facility, together with accrued interest, could be declared immediately due and payable.

Partnership Commodity Derivative Contracts

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on the prices of oil and natural gas and our ability to maintain and increase production through acquisitions and exploitation and development projects.

The Fund will assign certain commodity derivative financial instruments to us at the closing of this offering, and we intend to continue to enter into commodity derivative instruments to reduce the impact of oil and natural gas price volatility on our operations. The commodity derivative contracts to be assigned to us by the Fund will be swaps based on NYMEX oil and natural gas prices. On a pro forma basis at September 30, 2010, we had in place oil and natural gas swaps covering significant portions of our estimated oil and natural gas production through December 31, 2015. These swap agreements cover approximately 80% of our expected 2011 oil and natural gas production based on our reserve report dated June 30, 2010. The assigned swap agreements will cover, on average, 62% of our oil and natural gas production estimates for 2012 through 2015 based on our reserve report dated June 30, 2010.

The following table summarizes, for the periods indicated, the oil and natural gas swaps that will be assigned to us at the closing of this offering, on a pro forma basis as of December 31, 2010, through December 31, 2015. We expect to use swaps as a mechanism for managing commodity price risks whereby we pay the counterparty floating prices and receive fixed prices from the counterparty. By entering into the swap agreements, we will mitigate the effect on our cash flows of changes in the prices

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we receive for our oil and natural gas production. These transactions are settled based upon the NYMEX-WTI price of oil and NYMEX-Henry Hub price of natural gas.


	Oil (NYMEX-WTI)
	Weighted
	Average
Term	($/Bbl)		Bbls/d		% Hedged

2011	$	85.00		2,238		78	%
2012	$	85.25		2,039		64	%
2013	$	85.35		2,076		63	%
2014	$	84.58		2,090		63	%
2015	$	87.40		2,000		56	%


	Natural Gas
	(NYMEX-Henry Hub)
	Weighted
	Average
Term	($/MMBtu)		MMBtu/d		% Hedged

2011	$	7.26		9,178		84	%
2012	$	6.45		8,192		83	%
2013	$	6.45		7,474		78	%
2014	$	6.30		7,544		70	%
2015	$	5.52		3,398		31	%

Pro Forma Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to our oil and natural gas production. Pricing for oil and natural gas has been volatile for several years, and we expect this volatility to continue in the future. The prices we receive for our oil and natural gas production depend on many factors outside of our control, such as the strength of the global economy.

In order to reduce the impact of fluctuations in oil and natural gas prices on our revenues, or to protect the economics of property acquisitions, we intend to periodically enter into commodity derivative contracts with respect to a significant portion of our estimated oil and natural gas production through various transactions that fix the future prices received. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or we pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations.

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

For a summary of the oil and natural gas swaps and swap prices and resulting adjusted swap prices in place as of September 30, 2010, please read “— Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts” on page 124.

Collars. In a typical collar arrangement, we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price.

Interest Rate Risk

On a pro forma basis as of September 30, 2010, we had debt outstanding of $225 million, with an assumed weighted average interest rate of LIBOR plus 2.5%, or 3.02%. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $0.7 million. In the future, we anticipate entering into interest rate derivative contracts on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR.

Counterparty and Customer Credit Risk

Joint interest receivables arise from entities which own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. Please read “Business and Properties — Marketing and Major Customers” on page 162 for further detail about our significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative contracts expose us to credit risk in the event of nonperformance by counterparties.

While we do not require our customers to post collateral and do not have a formal process in place to evaluate and assess the credit standing of our significant customers or the counterparties on our derivative contracts, we do evaluate the credit standing of our customers and such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating and latest financial information or, in the case of a customer with which we have receivables, reviewing their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative contracts currently in place are lenders under our predecessor’s credit facilities, with investment grade ratings and we are likely to enter into any future derivative contracts with these or other lenders under our new credit facility that also carry investment grade ratings. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

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Predecessor Results of Operations

Factors Affecting the Comparability of the Historical Financial Results of Our Predecessor.

The comparability of our predecessor’s results of operations among the periods presented is impacted by:


	•	The following significant acquisitions by our predecessor:


	•	The Denbury Acquisition in May 2010 for approximately $893 million, and

	•	The acquisition of 80 producing natural gas wells located in Arkansas and Louisiana for approximately $48.7 million in January 28, 2009, which we refer to as the “Shongaloo Acquisition”;


	•	The sale of certain non-core oil and natural gas properties located in Alabama, Colorado, Louisiana, New Mexico, and Texas in August and September of 2009 for $16.3 million; and

	•	The shut-in of the Jay Field in December 2008, capital and other expenditures of $6.4 million to reconfigure the treating facility, reactivate wells and subsequently restart Jay Field in December 2009.

As a result of the factors listed above, historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

Nine Months Ended September 30, 2010 Compared to the Nine Months Ended September 30, 2009

Our predecessor recorded net income of approximately $51.0 million in the first nine months of 2010 compared to a net loss of $76.9 million in the first nine months of 2009. This increase in net income was primarily driven by increasing revenue and an increase in the fair value of commodity derivative contracts partially offset by an increase in operating costs and interest expense, reflecting the change in size of operations and associated debt financing during the nine months ended September 30, 2010.

Sales Revenues. Revenues for the nine months ended September 30, 2010 increased as compared to the nine months ended September 30, 2009 to approximately $175.5 million from approximately $53.1 million, respectively. Included in this increase were an increase in revenues from the sale of oil from $28.7 million to $113.0 million and an increase in revenues from the sale of natural gas from $16.2 million to $45.8 million. The overall increase in revenues was primarily driven by increases in commodity sales prices and our predecessor’s production volumes, including the impact of the Denbury Acquisition in May 2010, which closed on May 14, 2010, and the restarting of the Jay Field in December 2009, which resulted in increases in revenues of $65.0 million and $44.4 million, respectively, for the nine months ended September 30, 2010.

Our predecessor’s production volumes for the nine months ended September 30, 2010 included 1,573 MBbls of oil and 10,122 MMcf of natural gas, or 5,763 Bbl/d of oil and 37,077 Mcf/d of natural gas. On an equivalent net basis, production for the first nine months of 2010 was 3,488 MBoe, or 12,742 Boe/d. In comparison, our predecessor’s production volumes for the nine months ended September 30, 2009 included 566 MBbls of oil and 4,096 MMcf of natural gas, or 2,076 Bbl/d of oil and 15,003 Mcf/d of natural gas. On an equivalent net basis, production for the first nine months of 2009 was 1,401 MBoe, or 5,133 Boe/d. The primary drivers behind the increase in overall production volumes were the Denbury Acquisition completed in May 2010 and the restarting of the Jay Field in December 2009.

Our predecessor’s average sales price per Bbl for oil, excluding commodity derivative contracts, for the nine months ended September 30, 2010 was $71.82 compared with $50.56 per Bbl for the nine months ended September 30, 2009. Similarly, our predecessor’s average sales price per Mcf of natural gas,

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excluding commodity derivative contracts, for the nine months ended September 30, 2010 was $4.52 compared with $3.95 per Mcf for the nine months ended September 30, 2009.

Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, our predecessor recorded a net gain from its commodity hedging program in the first nine months of 2010 of approximately $46.5 million, composed of a realized gain of approximately $5.1 million and an unrealized gain of approximately $41.4 million. In contrast, our predecessor recorded a net loss from its commodity hedging program in the first nine months of 2009 of approximately $31.9 million, composed of a realized gain of approximately $42.2 million, offset by an unrealized loss of approximately $74.1 million.

Production Expenses. Our predecessor’s lease operating expenses increased from approximately $23.7 million in the nine months ended September 30, 2009 to approximately $52.2 million in the nine months ended September 30, 2010, primarily as a result of our predecessor’s increased production volumes described above, and included $11.0 million in additional lease operating expenses relating to the restarting of the Jay Field in December 2009 and $12.0 million in additional lease operating expenses as a result of the properties acquired in the Denbury Acquisition on May 14, 2010. On a per Boe basis, our predecessor’s unit lease operating expenses decreased from $16.93 per Boe produced in the nine months ended September 30, 2009 to approximately $14.95 per Boe produced in the nine months ended September 30, 2010, primarily as a result of increased volumes and the restart of the Jay Field. Production taxes increased from approximately $5.0 million in the nine months ended September 30, 2009 to approximately $12.5 million in the nine months ended September 30, 2010 primarily due to the increase in revenues discussed above. On a per Boe basis, production taxes remained relatively constant at $3.55 per Boe in the nine months ended September 30, 2009 as compared to $3.59 per Boe in the nine months ended September 30, 2010.

Impairment Expense. Our predecessor recorded an impairment of $28.3 million under the full cost ceiling test during the nine months ended September 30, 2009 due to decline in prices in the first quarter of 2009. No impairment was required during the nine months ended September 30, 2010.

Depreciation, Depletion and Amortization Expenses. Our predecessor’s depreciation, depletion and amortization expenses increased from approximately $13.7 million or $9.81 per boe in the nine months ended September 30, 2009 to approximately $45.1 million or $12.94 per boe in the nine months ended September 30, 2010. The overall increase was primarily a result of increasing production volumes from the restarting of the Jay Field in December 2009 and the completion of the Denbury Acquisition in May 2010. On a per Boe basis, the increase in depreciation, depletion and amortization expenses was primarily due to the step up in basis associated with the fair value allocation to our full cost pool for the Denbury acquisition.

General and Administrative and Other Expenses. Our predecessor’s general and administrative and other expenses increased from approximately $12.9 million in the nine months ended September 30, 2009 to approximately $19.4 million in the nine months ended September 30, 2010, primarily driven by transaction related costs of $2.9 million and significant staff increases in 2010 associated with our predecessor’s growth and approximately $1.5 million paid to Denbury during the nine months ended September 30, 2010 for transition services from the date of the acquisition in May 2010. General and administrative and other expenses decreased, however, on a per Boe basis from approximately $9.22 per Boe produced in the nine months ended September 30, 2009 to $5.56 per Boe produced in the nine months ended September 30, 2010 as a result of increased production volumes.

Gain on Equity Share Issuance. Our predecessor recorded a gain of $4.1 million during the nine months ended September 30, 2010 associated with a recapitalization that occurred within its equity investment in Ute Energy LLC.

Interest Expense. Our predecessor’s interest expense is comprised of interest on its credit facilities, amortization of debt issuance costs and gains(losses) on its interest rate derivative instruments. The increase in interest expense from $2.9 million in the nine months ended September 30, 2009 to $31.4 million in the nine months ended September 30, 2010 was primarily due to an increase in net

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losses on interest rate derivatives of approximately $21.0 million and an increase in interest on our predecessor’s credit facilities of $6.2 million.

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

Our predecessor recorded a net loss of approximately $115.4 million in 2009 compared to a net loss of approximately $268.5 million in 2008. This decrease in net loss was primarily driven by a substantial decrease in impairment of our predecessor’s oil and natural gas reserves from approximately $451.4 million in 2008 to approximately $28.3 million in 2009, partially offset by a significant decrease in revenues and a decrease in the fair value of derivative contracts.

Sales Revenues. Revenues for the year ended December 31, 2009 decreased significantly as compared to the year ended December 31, 2008, from approximately $281.1 million to approximately $72.8 million. Included in this decrease were a decline in revenues from the sale of oil from $170.7 million to $41.2 million and a decrease in revenues from the sale of natural gas from $53.8 million to $21.6 million. The overall decrease in oil revenues was primarily driven by the production being shut in at the Jay Field beginning in 2008, combined with significant decreases in sales prices for oil, and the decrease in revenues from the sale of natural gas was primarily due to significantly lower natural gas prices.

Our predecessor’s production volumes for the year ended December 31, 2009 were 739 MBbls of oil and 5,359 MMcf of natural gas. On an equivalent net basis, 2009 production was 1,838 MBoe, or 5,038 Boe/d. In comparison, our predecessor’s production volumes for the year ended December 31, 2008 were 1,753 MBbls of oil and 5,590 MMcf of natural gas. On an equivalent net basis, 2008 production was 2,824 MBoe, or 7,736 Boe/d. The primary driver behind the decrease in overall production volumes was the Jay Field shut-in.

Our predecessor’s average sales price per Bbl for oil, excluding commodity derivative contracts, for the year ended December 31, 2009 was $55.74 per Bbl compared with $97.40 per Bbl for the year ended December 31, 2008. Average sales prices for natural gas, excluding commodity derivative contracts, also decreased from $9.62 per Mcf in 2008 to $4.03 per Mcf in 2009.

Effects of Commodity Derivative Contracts. Due to changes in oil and natural gas prices, our predecessor recorded a net loss from its commodity hedging program in 2009 of approximately $63.1 million, composed of a realized gain of approximately $48.0 million, offset by an unrealized loss of approximately $111.1 million. In contrast, our predecessor recorded a net gain from its commodity hedging program in 2008 of approximately $134.6 million, composed of an unrealized gain of approximately $169.3 million, offset by a realized loss of approximately $34.7 million.

Production Expenses. Our predecessor’s lease operating expenses decreased from approximately $90.4 million, or $32.02 per Boe, in 2008 to approximately $33.3 million, or $18.13 per Boe, in 2009, primarily as a result of the Jay Field shut-in. Production taxes decreased from approximately $14.6 million in the year ended December 31, 2008 to approximately $7.6 million in the year ended December 31, 2009 primarily due to the decrease in revenues discussed above. On a per Boe basis, production taxes decreased from $5.16 per Boe in the year ended December 31, 2008 to $4.13 per Boe in the year ended December 31, 2009 primarily due to the decrease in sales prices of oil and natural gas sold, as discussed above.

Impairment Expense. Our predecessor recorded a substantial impairment under the full cost ceiling test of approximately $451.4 million in 2008, predominantly as a result of the low oil and natural gas price environment at the end of 2008 and as a result of our decision to shut in the Jay Field during this period. The comparable impairment for the year ended December 31, 2009 was approximately $28.3 million.

Depreciation, Depletion and Amortization Expenses. Our predecessor’s depreciation, depletion and amortization expenses also decreased significantly from approximately $49.3 million, or $17.46 per Boe produced, in 2008 to approximately $17.0 million, or $9.24 per Boe produced, in 2009. The decrease is

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a direct result of the full cost ceiling impairment recognized in 2008, which decreased the carrying amount of our predecessor’s oil and natural gas properties subject to depletion by $451.4 million.

General and Administrative and Other Expenses. Our predecessor’s general and administrative and other expenses increased from approximately $14.9 million, or $5.26 per Boe produced, in 2008 to approximately $19.5 million, or $10.59 per Boe produced, in 2009. General and administrative and other expenses increased with the move of our predecessor’s headquarters from Denver to Houston.

Interest Expense. The decrease in interest expense from $13.0 million in the year ended December 31, 2008 to $3.8 million in the year ended December 31, 2009 was primarily due to a decrease in net losses on interest rate derivatives of approximately $3.0 million and a decrease in interest on our predecessor’s credit facilities of $6.3 million.

Year Ended December 31, 2008 Compared to the Year Ended December 31, 2007

Our predecessor recorded a net loss of approximately $268.5 million in 2008 compared to a net loss of approximately $168.7 million in 2007. This increase in net loss was driven primarily by the substantial impairment charge of approximately $451.4 million, partially offset by a significant increase in revenues and an increase in the fair value of derivative contracts.

Sales Revenues. Our predecessor’s revenues for the year ended December 31, 2008 increased significantly as compared to the year ended December 31, 2007 from approximately $171.3 million to approximately $281.1 million. Included in this increase were increases in revenues from the sale of oil from $120.0 million to $170.7 million and increases in revenues from the sale of natural gas from $37.3 million to $53.8 million. The increase in revenues was primarily attributable to higher oil and natural gas prices in 2008 as compared to 2007.

Our predecessor’s production volumes for the year ended December 31, 2008 were 1,753 MBbls of oil and 5,590 MMcf of natural gas. On an equivalent net basis, 2008 production was 2,824 MBoe, or 7,736 Boe/d. In comparison, our predecessor’s production volumes for the year ended December 31, 2007 were 1,668 MBbls of oil and 5,476 MMcf of natural gas. On an equivalent net basis, 2007 production was 2,701 MBoe, or 7,401 Boe/d.

Our predecessor’s average realized sales price, excluding commodity derivative contracts, for oil for the year ended December 31, 2008 was $97.40 per Bbl compared with $71.94 per Bbl for the year ended December 31, 2007. Average sales prices for natural gas excluding commodity derivative contracts increased to $9.62 per Mcf in 2008 to $6.81 per Mcf in 2007.

Effects of Commodity Derivative Contracts. Due to changes in commodity prices, our predecessor recorded a net gain from its commodity hedging program in 2008 of approximately $134.6 million, composed of a realized loss of approximately $34.7 million, offset by an unrealized gain of approximately $169.3 million. In contrast, our predecessor recorded a net loss from its commodity hedging program in 2007 of approximately $150.4 million, comprised of a realized gain of approximately $6.9 million, offset by an unrealized loss of approximately $157.3 million.

Production Expenses. Our predecessor’s lease operating expenses increased in 2008 to approximately $90.4 million from approximately $77.8 million in 2007, primarily as a result of increased production volumes. Production taxes increased from approximately $13.0 million in the year ended December 31, 2007 to approximately $14.6 million in the year ended December 31, 2008 primarily due to the increase in revenues discussed above. On a per Boe basis, production taxes increased from $4.80 per Boe in the year ended December 31, 2007 to $5.16 per Boe in the year ended December 31, 2008 primarily due to the increase in sales prices of oil and natural gas sold, as discussed above.

Impairment Expense. Our predecessor did not record an impairment under the full cost ceiling test in 2007. In 2008, however, our predecessor recorded a substantial impairment under the full cost ceiling test of approximately $451.4 million, partially as a result of the low oil and natural gas price

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environment at the end of 2008 and partially as a result of our decision to shut in the Jay Field during this period.

Depreciation, Depletion and Amortization Expenses. Our predecessor’s depreciation, depletion and amortization expenses increased from approximately $42.9 million, or $15.88 per Boe produced, in 2007 to approximately $49.3 million, or $17.46 per Boe produced, in 2008, primarily due to an increase in capitalized drilling costs in 2008.

General and Administrative and Other Expenses. Our predecessor’s general and administrative and other expenses decreased from approximately $20.7 million, or $7.66 per Boe produced, in 2007 to approximately $14.9 million, or $5.26 per Boe produced, in 2008, primarily driven by a reduction in personnel.

Interest Expense. The decrease in interest expense from $17.4 million in the year ended December 31, 2007 to $13.0 million in the year ended December 31, 2008 was primarily due to a decrease in interest on our predecessor’s credit facilities of $6.8 million due to the reduction in principal balance, partially offset by an increase in net losses on interest rate derivatives of approximately $2.4 million.

Predecessor Liquidity and Capital Resources

Our predecessor’s primary sources of capital and liquidity have been proceeds from bank borrowings, capital contributions from the partners of its limited partnerships and cash flow from operations. To date, our predecessor’s primary use of capital has been for the acquisition of oil and natural gas properties.

Net bank borrowings were approximately $226.3 million, $88.8 million, $86.5 million, $88.2 million and $547.7 million at December 31, 2007, 2008 and 2009 and September 30, 2009 and 2010, respectively. Net bank borrowings during those periods were used primarily to fund acquisitions of oil and natural gas properties and for working capital. A total of $194.4 million was invested in the development of oil and natural gas properties during those periods. During the first nine months of 2010, our predecessor incurred approximately $461.2 million of indebtedness in connection with the Denbury Acquisition.

Predecessor Cash Flows

Net cash provided by operating activities was approximately $24.8 million, $75.3 million, $64.9 million, $44.6 million and $50.8 million for the years ended December 31, 2007, 2008 and 2009 and the nine months ended September 30, 2009 and 2010, respectively. Revenues increased significantly from the nine months ended September 30, 2009 to the nine months ended September 30, 2010, and hence our net cash provided by operating activities increased during that same period. Cash provided by (used in) operating activities is impacted by the prices received for oil and natural gas sales and levels of production volumes. Our predecessor’s production volumes in the future will in large part be dependent upon the dollar amount and results of future capital expenditures. Future levels of capital expenditures made by our predecessor may vary due to many factors, including drilling results, oil and natural gas prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.

Net cash used in investing activities by our predecessor was approximately $73.0 million, $137.2 million, $55.5 million, $41.3 million and $931.0 million for the years ended December 31, 2007, 2008 and 2009 and the nine months ended September 30, 2009 and 2010, respectively. The increase in cash used in investing activities from 2007 to 2008 was principally due to increased additions to oil and gas properties and investment in Ute Energy and marketable equity securities. The decrease from 2008 to 2009 was mainly due to reduced additions to oil and gas properties, along with fewer proceeds received from the sale of oil and gas properties, partially offset by the acquisition of the Shongaloo properties. The cash used in investing activities for the nine months ended September 30, 2010 was attributable to the Denbury Acquisition.

Net cash provided by (used in) financing activities by our predecessor was approximately $89.9 million, $30.2 million, $(13.3) million, $(5.7) million and $884.5 million for the years ended December 31, 2007, 2008 and 2009 and the nine months ended September 30, 2009 and 2010,

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respectively. The decrease in cash provided by financing activities from 2007 to 2008 was the result of a repayment of bank borrowings, partially offset by contributions by partners and minority interest owners. The cash inflow during the nine months ended September 30, 2010 was primarily attributable to contributions by partners and minority interest owners and from increased bank borrowings to fund the Denbury Acquisition.

Predecessor Working Capital

Our predecessor’s working capital totaled $(0.1) million and $24.0 million at December 31, 2009 and September 30, 2010, respectively. Our predecessor’s collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our predecessor’s cash balances totaled $17.2 million and $21.3 million at December 31, 2009 and September 30, 2010, respectively.

Predecessor Commodity Derivative Contracts

The following table summarizes, for the periods presented, our predecessor’s oil and natural gas swaps in place as of September 30, 2010 through December 31, 2015. Our predecessor uses swaps as a mechanism for managing commodity price risks whereby it pays the counterparty floating prices and receives fixed prices from the counterparty. By entering into the swap agreements, our predecessor mitigates the effect on its cash flows of changes in the prices it receives for its oil and natural gas production. These transactions are settled based upon the NYMEX-WTI price of oil and NYMEX-Henry Hub price of natural gas on the average of the three final trading days of the month, with settlement occurring on the fifth day of the production month.


	Oil
	(NYMEX-WTI)
	Weighted
	Average
Term	($/Bbl)		Bbls/d

2010	$	76.77		6,380
2011	$	76.02		5,521
2012	$	76.46		4,644
2013	$	75.43		4,591
2014	$	80.62		2,741
2015	$	87.40		2,000


	Natural Gas
	(NYMEX-Henry Hub)
	Weighted
	Average
Term	($/MMBtu)		MMBtu/d

2010	$	4.83		46,834
2011	$	5.66		42,660
2012	$	5.84		34,161
2013	$	6.06		30,765
2014	$	6.23		26,347
2015	$	5.52		6,100

In addition to the oil and natural gas swap contracts in place, our predecessor has also entered into oil and natural gas collars related to certain portions of its expected production. The following table

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summarizes, for the periods indicated, our predecessor’s oil and natural gas collars as of September 30, 2010:


			Weighted		Weighted
			Average		Average
	Volume Per	Quantity	Floor		Ceiling		Price	Contract
Collars	Day	Type	Pricing		Pricing		Index	Period

Oil	700	Bbls	$	70.00	$	110.00	NYMEX-WTI	1/1/11 - 12/31/12
Oil	70	Bbls	$	60.00	$	78.27	NYMEX-WTI	1/1/12 - 12/31/14
Oil	1,750	Bbls	$	70.00	$	108.25	NYMEX-WTI	1/1/14 - 12/31/15
Natural Gas	1,598	MMBtu	$	7.00	$	8.90	NYMEX-Henry Hub	1/1/10 - 12/31/10
Natural Gas	2,518	MMBtu	$	6.50	$	8.70	NYMEX-Henry Hub	1/1/12 - 12/31/14

The following tables summarize, as of September 30, 2010, for the periods presented, certain financial instruments entered into to fix the basis differential of our predecessor’s natural gas production during the period from January 1, 2010 through December 31, 2014. These contracts are designed to effectively fix a price differential between the NYMEX-Henry Hub price and the index price at which the physical natural gas is sold. Although our predecessor markets its natural gas production at numerous delivery points, it only has basis differential derivative contracts with respect to natural gas delivered to Texas Gas Transmission Corp. which were entered into to address production associated with the Shongaloo acquisition.


	Texas Gas Transmission Corp.
								Basis
	NYMEX-Henry Hub							Adjusted
	Swap Price				Basis per			Swap Price
Term	per MMBtu		MMBtu/d		MMBtu			per MMBtu

2010	$	3.94		3,261	$	(0.17	)	$	3.77
2011	$	4.44		2,967	$	(0.16	)	$	4.28
2012	$	5.07		2,630	$	(0.16	)	$	4.91
2013	$	5.29		2,473	$	(0.15	)	$	5.14
2014	$	5.42		2,473	$	(0.15	)	$	5.27

The Fund’s Credit Facilities

In May 2010, to partially fund the Denbury Acquisition, the Fund entered into three separate credit agreements that mature in 2014, which we refer to as the Credit Facilities, with a syndicated bank group. The Credit Facilities have an aggregate maximum commitment of $850 million, which includes a $200 million accordion option, and an aggregate current borrowing base of $650 million. Two of the Credit Facilities are secured by mortgages on oil and natural gas properties, including the Partnership Properties, and related assets and the other Credit Facility is secured by the borrower’s preferred limited partner interest in one of its subsidiaries. We expect that the Credit Facilities will be amended to permit the contribution of the Partnership Properties by the Fund to us in connection with the closing of this offering.

Borrowings under the Credit Facilities bear interest at the alternative base rate, or ABR, or the Eurodollar Rate plus a margin based on the borrowing base utilization. The ABR is defined as the higher of the prime rate or the sum of the Federal Funds Effective Rate plus one-half percent. The Eurodollar Rate is defined as the applicable London Interbank Offer Rate for deposits in U.S. dollars.

As of September 30, 2010, the weighted average interest rate was 3.02% under the Credit Facilities. Our predecessor’s aggregate borrowings under the Credit Facilities totaled $547.7 million at September 30, 2010.

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The Credit Facilities contain financial and other covenants, including a current ratio test and an interest coverage test. The Fund and its affiliates were in compliance with all covenants at September 30, 2010.

It is expected that the Fund and its affiliates will use a portion of the cash they receive from us at the closing of this offering, as partial consideration for the contribution of the Partnership Properties, to repay outstanding borrowings and reduce the aggregate commitments under the Credit Facilities. Please read “Use of Proceeds” on page 66.

Predecessor Contractual Obligations

A summary of our predecessor’s contractual obligations in millions as of September 30, 2010 is provided in the following table.


	Obligations Due in Period
Contractual Obligation	2010		2011-2012		2013-2014		Thereafter		Total

Long-term debt	$	—	$	—	$	547.7	$	—	$	547.7
Interest on long-term debt(a)		4.3		34.1		24.2		—		62.6
Capital leases(b)		—		0.1		—		—		0.1
Operating leases(b)		0.3		1.3		—		—		1.6

Total contractual obligations	$	4.6	$	35.5	$	571.9	$	—	$	612.0


(a)		Based upon the weighted average interest rate of approximately 3.02% under the Credit Facilities at September 30, 2010.


(b)		See note 12 to our predecessor’s audited consolidated financial statements as of and for the period ended December 31, 2009 for a description of lease obligations.

Predecessor Quantitative and Qualitative Disclosure About Market Risk

Our predecessor is exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.

The primary objective of the following information is to provide quantitative and qualitative information about our predecessor’s potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our predecessor’s market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our predecessor’s major market risk exposure is in the pricing that it receives for its oil and natural gas production. Realized pricing is primarily driven by the spot market prices applicable to its natural gas production and the prevailing price for oil. Pricing for oil and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices our predecessor receives for its oil and natural gas production depend on many factors outside of its control, such as the strength of the global economy.

To reduce the impact of fluctuations in oil and natural gas prices on our predecessor’s revenues, or to protect the economics of property acquisitions, our predecessor periodically enters into commodity derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix the future prices received. These transactions may include price swaps whereby our predecessor will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, our predecessor may enter into collars, whereby our predecessor

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receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage our predecessor’s exposure to oil and natural gas price fluctuations. Our predecessor does not enter into derivative contracts for speculative trading purposes.

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

For a summary of the oil and natural gas swaps and oil and natural gas swap prices, related basis swap prices and resulting adjusted swap prices in place as of September 30, 2010, please read “— Predecessor Liquidity and Capital Resources — Predecessor Commodity Derivative Contracts” on page 132.

Collars. In a typical collar arrangement, our predecessor receives the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price.

For a summary of the oil and natural gas collars in place as of September 30, 2010, please read “— Predecessor Liquidity and Capital Resources — Predecessor Commodity Derivative Contracts” on page 132.

Interest Rate Risk

At September 30, 2010, our predecessor had $547.7 million of debt outstanding under the Credit Facilities, with a weighted average floating interest rate of 3.02%. Assuming no change in the amount outstanding, the impact on interest expense of a 10% increase or decrease in the average interest rate, after giving effect to our predecessor’s existing interest rate swaps, would be approximately $0.4 million.

Counterparty and Customer Credit Risk

Joint interest receivables arise from entities which own partial interests in the wells our predecessor operates. These entities participate in our predecessor’s wells primarily based on their ownership in leases on which our predecessor drills. Our predecessor has limited ability to control participation in its wells. Our predecessor is also subject to credit risk due to the concentration of its oil and natural gas receivables with several significant customers. Please read “Business and Properties — Marketing and Major Customers” on page 162 for further detail about our predecessor’s significant customers. The inability or failure of our predecessor’s significant customers to meet their obligations to our predecessor or their insolvency or liquidation may adversely affect our predecessor’s financial results. In addition, our predecessor’s oil and natural gas derivative contracts expose our predecessor to credit risk in the event of nonperformance by counterparties.

While our predecessor does not require its customers to post collateral and does not have a formal process in place to evaluate and assess the credit standing of its significant customers or the counterparties on its derivative contracts, our predecessor does evaluate the credit standing of its customers and such counterparties as it deems appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating and latest financial information or, in the case of a customer with which our predecessor has receivables, reviewing their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our predecessor’s derivative contracts currently in place are lenders under the Credit Facilities, with investment grade ratings and our predecessor is likely to enter into any future derivative contracts with these or other lenders under the Credit Facilities that also carry investment grade ratings. Several of our predecessor’s significant customers for oil and natural gas receivables have a credit rating below

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investment grade or do not have rated debt securities. In these circumstances, our predecessor has considered the lack of investment grade credit rating in addition to the other factors described above.

Critical Accounting Policies and Estimates

The discussion and analysis of our predecessor’s and our financial condition and results of operations are based upon each of our respective consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Estimates and assumptions are evaluated on a regular basis. We and our predecessor base our respective estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from the estimates and assumptions used in preparation of the financial statements. What follows is a discussion of the more significant accounting policies, estimates and judgments.

Upon the closing of this offering, the consolidated historical financial statements of our predecessor will become the historical financial statements of QR Energy, LP. Consequently, the critical accounting policies and estimates of our predecessor will become our critical accounting policies and estimates. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of the financial statements. Please read Note 2 of the Notes to the Consolidated Financial Statements of our predecessor, included elsewhere in this prospectus, for a discussion of additional accounting policies, estimates and judgments made by its management.

Oil and Natural Gas Reserve Quantities

Our and our predecessor’s estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Miller and Lents, Ltd., our and our predecessor’s independent reserve engineering firm, prepares a fully-engineered reserve and economic evaluation of all our properties on a lease, unit or well-by-well basis, depending on the availability of well-level production data. 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. The estimates of the proved reserves attributable to the Partnership Properties as of June 30, 2010 included in this prospectus are based on a reserve report prepared by Miller & Lents, Ltd., our independent reserve engineers. On a going forward basis, we expect that Miller & Lents, Ltd. will prepare a reserve report as of December 31 of each year, and we will prepare internal estimates of our proved reserves as of June 30 of each year.

We and our predecessor prepare our reserve estimates, and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines, which is used for our quarterly ceiling tests. Our independent engineering firm adheres to the same guidelines when preparing their reserve reports. The accuracy of our and our predecessor’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various economic assumptions, and the judgments of the individuals preparing the estimates.

Our and our predecessor’s proved reserve estimates are also a function of many assumptions, all of which could deviate significantly from actual results. For example, when the price of oil and natural gas increases, the economic life of our and our predecessor’s properties is extended, thus increasing estimated proved reserve quantities and making certain projects economically viable. Likewise, if oil and natural gas prices decrease, the properties economic life is reduced and certain proved projects may

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become uneconomic, reducing estimated proved reserved quantities. Oil and natural gas price volatility adds to the uncertainty of our and our predecessor’s reserve quantity estimates. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and natural gas liquids eventually recovered.

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-03 to align the oil and natural gas reserve estimation and disclosure requirements of Extractive Industries — Oil and Gas Topic of the Accounting Standards Codification with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements. We implemented ASU 2010-03 as of December 31, 2009. Key items in the new rules include changes to the pricing used to estimate reserves and calculate the full cost ceiling limitation whereby an unweighted average of the first-day-of-the-month price for each month within the applicable twelve-month period is used rather than a single day spot price, the use of new technology for determining reserves, the ability to include nontraditional resources in reserves and permitting disclosure of probable and possible reserves.

Full Cost Method of Accounting

The accounting for our and our predecessor’s businesses is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. We and our predecessor follow the full cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. Exploration and development costs include dry-well costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding natural gas and oil reserves. Amortization of natural gas and oil properties is provided using the unit-of-production method based on estimated proved natural gas and oil reserves. Sales and abandonments of natural gas and oil properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and estimated proved natural gas and oil reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.

In accordance with full cost accounting rules, capitalized costs are subject to a limitation. The capitalized cost of natural gas and oil properties, net of accumulated depreciation, depletion and amortization, less any related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from estimated proved natural gas and oil reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less related tax effects (the “ceiling limitation”). Beginning with the December 31, 2009 calculation, our and our predecessor’s full cost ceiling limitation is calculated using the unweighted arithmetic average first-day-of-the-month natural gas and oil prices for the most recent prior 12 months as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. Prior to December 31, 2009, the full cost ceiling limitation calculation required companies to use natural gas and oil prices on the last day of the period. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down is not reversible at a later date. During the year ended December 31, 2009, total capitalized costs of our predecessor’s natural gas and oil properties exceeded its ceiling limitation, resulting in a non-cash ceiling impairment of $28.3 million, all of which was incurred in the first quarter of 2009 under the previous rules in effect at the time. On a pro forma basis, approximately $13.9 million of this amount was attributable to the Partnership Properties. For the year ended December 31, 2008, total capitalized costs of our predecessor’s natural gas and oil properties exceeded our predecessor’s ceiling limitation, as calculated under the previous rules, resulting in a non-cash ceiling impairment of $449.7 million.

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Unevaluated Properties

The balance of unevaluated properties consists of capital costs incurred for undeveloped acreage, wells and production facilities in progress and wells pending determination, together with capitalized interest costs for these projects. These costs are initially excluded from our and our predecessor’s amortization base until the outcome of the project has been determined or, generally, until it is known whether proved reserves will be assigned to the property. We and our predecessor assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. We and our predecessor assess our respective properties on an individual basis or as a group if properties are individually insignificant. Our and our predecessor’s assessments include consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. We estimate that substantially all of our respective costs classified as unproved as of the balance sheet date will be evaluated and transferred within a five year period from the date of acquisition, contingent on our respective capital expenditures and drilling programs.

Asset Retirement Obligation

The initial estimated retirement obligation associated with oil and natural gas properties is recognized as a liability, with a corresponding increase in the carrying value of oil and natural gas properties. Amortization expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

Revenue Recognition and Natural Gas Balancing

Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. We and our predecessor account for oil and natural gas production imbalances using the sales method, whereby we and our predecessor recognize revenue on all natural gas and oil sold to our customers notwithstanding the fact that its ownership may be less than 100% of the oil and natural gas sold. Liabilities are recorded for imbalances greater than our respective proportionate shares of remaining estimated and oil natural gas reserves.

Derivative Contracts and Hedging Activities

Current accounting rules require that all derivative contracts, other than those that meet specific exclusions, be recorded at fair value. Quoted market prices are the best evidence of fair value. If quotations are not available, management’s best estimate of fair value is based on the quoted market price of derivatives with similar characteristics or on other valuation techniques.

Our and our predecessor’s derivative contracts are either exchange-traded or transacted in an over-the-counter market. Valuation is determined by reference to readily available public data. Option fair values are based on the Black-Scholes option pricing model and verified against the applicable counterparty’s fair values.

We and our predecessor recognize all of our respective derivative contracts as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative contract depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative contracts that are designated and qualify as hedging instruments, we designate the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. For derivative contracts not designated as

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hedging instruments, the gain or loss is recognized in current earnings during the period of change. None of our or our predecessor’s derivatives was designated as a hedging instrument during 2009, 2008 and 2007 and the nine months ended September 30, 2010.

Recently Issued Accounting Pronouncements

On July 21, 2010, the FASB issued ASU 2010-20 “Receivables (Topic 310) — Disclosures about the Credit Quality of Financial Receivables and the Allowance for Credit Losses.” ASU 2010-20 requires disclosure of additional information to assist financial statement users to understand more clearly an entity’s credit risk exposures to finance receivables and the related allowance for credit losses. ASU 2010-20 is effective for all public companies for interim and annual reporting periods ending on or after December 15, 2010, with specific items, such as the allowance rollforward and modification disclosures, effective for periods beginning after December 15, 2010. We do not expect the adoption of this new guidance to have an impact on our financial position, cash flows or results of operations.

In April 2010, the FASB issued ASU 2010-14, which amends the guidance on oil and natural gas reporting in Accounting Standards Codification 932.10.S99-1 by adding the Codification of SEC Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.

In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures About Fair Value Measurements,” which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3 disclosures effective beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. Both the current and future adoption does not have a material impact on our or our predecessor’s financial position or results of operations.

Internal Controls and Procedures

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 its 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.


	•	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.

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	•	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.

In the third quarter of 2010, management began to take steps to address the causes of the 2009 and 2010 adjustments by putting into place new accounting processes and control procedures and has hired additional personnel.

While we have begun the process of evaluating our internal control over financial reporting, 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.

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 Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2007, 2008 and 2009. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy, and we tend to experience inflationary pressure on the cost of oilfield services and equipment, as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

Currently, neither we nor our predecessor have any off-balance sheet arrangements.

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BUSINESS AND PROPERTIES

The following Business and Properties discussion should be read in conjunction with the “Selected Historical and Pro Forma Financial Data” beginning on page 109 and the accompanying financial statements and related notes included elsewhere in this prospectus. Unless otherwise indicated, all references to financial or operating data on a pro forma basis give effect to the transactions described under “Prospectus Summary — Formation Transactions and Partnership Structure” on page 8 and in the Unaudited Pro Forma Condensed Financial Statements included elsewhere in this prospectus.

Overview

We are a Delaware limited partnership formed in September 2010 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. 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 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 at mutually agreeable prices. 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” beginning on page 146.

Our Properties

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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.


												Average Net
	Estimated Pro Forma									Standardized		Pro Forma				Producing
	Net Proved Reserves (MBoe)						% Oil and			Measure(1)		Production				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(2)		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)		Standardized measure is calculated in accordance with Statement of Financial Accounting Standards 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.

(2)		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 “— Summary of Oil and Natural Gas Properties and Projects — 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 derivative contract pricing becomes favorable. For a description of our commodity derivative contracts, please read “Management’s Discussion and

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Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — Partnership Commodity Derivative Contracts” on page 124.

Our Business Strategies


	•	*Pursue Accretive Acquisitions of Long-Lived, Low-Risk Producing Oil and Natural Gas Properties Throughout North America.* We will seek to acquire properties containing long-lived onshore reserves with low production decline rates and low-risk identified development potential. In addition, we will seek to acquire large and mature oil and natural gas fields with opportunities for incremental improvements in hydrocarbon recovery through operational improvements and secondary and tertiary recovery techniques, which we believe will offer us the most potential to improve efficiency and increase reserves, production and cash flows. We believe that our experience positions us to identify, evaluate, execute, integrate and exploit suitable acquisitions.

	•	*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.* We expect to have the opportunity to make acquisitions of producing oil and natural gas properties directly from the Fund from time to time in the future. Under the terms of our omnibus agreement, the Fund will agree to offer us the first opportunity to purchase properties that it may offer for sale, so long as at least 70% of the allocated value is attributable to proved developed producing reserves. While the Fund is not obligated to sell any properties to us, we believe that selling properties to us will enhance the Fund’s economic returns by monetizing long-lived producing properties while potentially retaining a portion of the resulting cash flow through distributions on its limited partner interest in us.

	•	Leverage Our Relationships 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. The Fund and Quantum Energy Partners each have long histories of pursuing and consummating oil and natural gas property acquisitions in North America. Through our relationships with the Fund and Quantum Energy Partners, we will have access to their significant pool of management talent and industry relationships, which we believe will provide us a competitive advantage in pursuing potential third-party acquisition opportunities. The Fund will commit, pursuant to the omnibus agreement, to offer us the first option to participate in at least 25% of each acquisition for which at least 70% of the allocated value is attributable to proved developed producing reserves. Additionally, we expect to have the opportunity to work jointly with the Fund and Quantum Energy Partners to pursue certain acquisitions of oil and natural gas properties that may not otherwise be attractive acquisition candidates for any of us individually. We believe this arrangement will give us access to an array of third-party acquisition opportunities that we would not otherwise be in a position to pursue.

	•	*Reduce Costs and Maximize Recovery to Drive Value Creation in Our Producing Properties.* We intend to increase our reserves and production through development and exploitation drilling and operational enhancements that we believe to be low-risk. Through our general partner’s relationship with Quantum Resources Management, we have significant technical expertise that we believe will allow us to identify and implement exploitation opportunities in order to maximize reserve recovery on our current properties, as well as those properties that we may acquire in the future.

	•	*Mitigate Commodity Price Risk and Maximize Cash Flow Visibility Through a Disciplined Commodity Hedging Policy.* We expect to adopt a hedging policy to reduce the impact to our

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		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. The Partnership Properties that we acquire at the closing of this offering will include 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 believe these commodity derivative contracts will allow us to mitigate the impact of oil and natural gas price volatility, thereby maximizing our cash flow visibility.


	•	*Maintain a Balanced Capital Structure to Provide Financial Flexibility for Acquisitions.* We intend to maintain relatively low levels of indebtedness in relation to our cash flows from operations. We believe our internally generated cash flows and our borrowing capacity under our new credit facility will provide us with the financial flexibility to exploit organic growth opportunities and allow us to pursue additional acquisitions of producing oil and natural gas properties.

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 properties and operations are broadly distributed across four diverse producing regions, producing from multiple formations in 84 different fields, across 8 states. For the nine months ended September 30, 2010, our average net daily production was weighted toward oil and NGLs, with 57% crude oil and NGLs and 43% natural gas. Our properties have well understood geologic features, relatively predictable production profiles and modest capital requirements, which we believe make them well-suited for our objective of generating stable cash flows and, over time, increasing our cash flows. Many of our properties have been producing for more than 50 years and approximately 42% of our fields, based on standardized measure, have been producing since at least the 1970s, and our proved developed producing properties have a future average annual decline rate of 9% over the next ten years based on our reserve report dated June 30, 2010.

	•	*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.* The Fund’s acquisition criteria are very similar to ours, and, as such, most of the Fund’s retained assets will have reserve characteristics suitable for a limited partnership such as ours. After contributing the Partnership Properties to us, the Fund will retain a portfolio of oil and natural gas assets with aggregate estimated proved reserves of 56.4 MMBoe as of June 30, 2010 and aggregate average net production of 13,132 Boe/d for the nine months ended September 30, 2010. Based on the suitability of the majority of the Fund’s retained assets, and the Fund’s significant ownership in us, we believe we are well positioned to acquire additional assets from the Fund in the future. 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.

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	•	*Our Relationship with Quantum Resources Management, Which Provides Us with Extensive Technical Expertise in and Familiarity with Our Core Focus Areas.* Through the services agreement with Quantum Resources Management, we have the operational support of a staff of 16 petroleum professionals with significant technical expertise and access to state-of-the-art reservoir engineering and geoscience technologies. We believe that this technical expertise, which includes expertise in secondary and tertiary recovery methods, differentiates us from, and provides us with a competitive advantage over, many of our competitors. We intend to utilize these resources in maximizing our production and ultimate reserve recovery, which could add substantial value to our assets.

	•	*Our Relationship with Quantum Energy Partners, Which Will Help Us in the Evaluation and Execution of Future Acquisitions*. We believe that our ability to use Quantum Energy Partners’ industry relationships and broad expertise in evaluating oil and natural gas assets will expand our opportunities and differentiate us from many of our competitors. Additionally, we expect to have the opportunity to work jointly with Quantum Energy Partners to pursue acquisitions of oil and natural gas properties that we would not otherwise be able to pursue on our own or that may not otherwise be attractive acquisition candidates for either of us individually.

	•	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. As of June 30, 2010, we operated 83% of our assets, as measured by value, based on standardized measure. Following the closing of this offering, we will continue to operate the majority of our reserves and production, which will allow us to better manage our operating costs. We believe that this substantial operational control of our producing properties will also allow us to maximize the value of our properties and the stability of our cash flows, as well as better control the timing and costs of our development activities.

	•	*Our Management Team’s Extensive Experience in the Acquisition, Development and Integration of Oil and Natural Gas Assets*. The members of our management team have an average of over 27 years of experience in the oil and natural gas industry. Alan L. Smith, the Chief Executive Officer of our general partner, has 25 years of oil and natural gas industry experience, a strong commercial and technical background and has built and operated successful independent exploration and production companies. John Campbell, the President and Chief Operating Officer of our general partner, has spent the last 25 years managing technical and field operations in the oil and natural gas business, resulting in significant operational experience and extensive knowledge of North American oil and natural gas basins that we believe will allow us to successfully evaluate, develop and optimize our properties and potential acquisitions. Donald Wolf, the Chairman of the Board of our general partner, has spent over 40 years in the leadership of companies in the oil and natural gas sector, giving him extensive experience within the industry that we believe will provide a strong foundation for managing and enhancing our operations, accessing strategic opportunities and developing our assets. In their roles at the Fund, our management team has managed the acquisition and integration of numerous oil and natural gas properties, including the Fund’s recent $893 million Denbury Acquisition.

	•	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. At June 30, 2010, the Partnership Properties included 9.4 MMBoe of estimated proved undeveloped reserves, of which 82% were oil, and had identified 315 low-risk proved development projects. We intend to develop an average of approximately 65 identified projects per year, which we believe will permit us to grow our current annual production through December 31, 2015, based on our reserve report dated June 30, 2010.

	•	*Our Competitive Cost of Capital and Financial Flexibility.* Unlike our corporate competitors, we do not expect to be subject to federal income taxation at the entity level. We believe that this

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		attribute should provide us with a lower cost of capital compared to many of our competitors, thereby enhancing our ability to compete for future acquisitions both individually and jointly with the Fund and Quantum Energy Partners. Our ability to issue additional common units and other partnership interests in connection with acquisitions will enhance our financial flexibility. We believe our competitive cost of capital and financial flexibility will enable us to be competitive in seeking to acquire oil and natural gas properties.

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 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

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. 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. 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

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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 the Fund from structuring its asset dispositions in an attempt to circumvent our contractual rights under the omnibus agreement.

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 closing of this offering. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement” on page 188.

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 other 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

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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.

Properties

Our general partner and the Fund used a number of qualitative and quantitative screening criteria in deciding which assets would be contributed to us from the Fund’s portfolio, including primarily:


	•	Hydrocarbon mix: based on the current price environment for oil and natural gas, our general partner and the Fund believed it was appropriate and advisable that the Partnership Properties be weighted toward oil;

	•	Geographic diversity: in order to more closely mirror the Fund’s portfolio of assets, our general partner and the Fund selected a mix of assets to contribute to us from each of the Fund’s primary operating regions, which we believe will help us to mitigate regional pricing or demand issues; and

	•	Modest future capital expenditure requirements: because we will be required to distribute all of our available cash, and because our strategy will be to grow our distributions over time, our general partner and the Fund did not believe it would be appropriate to contribute assets to us that would require us to make substantial capital expenditures.

Our properties and the Fund’s retained properties consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, predictable production profiles. Specifically, our properties and the Fund’s properties are composed of oil and natural gas properties located in fields that generally have been producing for a long period of time, typically more than ten years. Observing the performance of these fields over many years allows for greater understanding of production and reservoir characteristics, making future performance more predictable. In other words, the production and corresponding decline rates attributable to properties of this type, in contrast with more recently drilled properties, can be forecasted with a greater degree of accuracy. Similarly, we use words such as “mature” or “legacy” to describe our properties as having established operating, reservoir and production characteristics. The properties selected for inclusion among the Partnership Properties were chosen, in part, because we expect that the greater precision in forecasted production attributable to the properties will result in more stable cash flows.

The development and production of oil and natural gas has a number of uncertainties that pose substantial risk, even for mature properties such as ours and the Fund’s. However, we view our and the Fund’s properties as less risky because many of the operational risks associated with oil and natural gas production (for example, drilling a well, whether one will discover hydrocarbons capable of production in paying quantities and initial production decline rate) tend to occur earlier in the lifecycle of oil and gas properties. For a discussion of the risks inherent in oil and natural gas production, please read “Risk Factors — Risks Related to Our Business — 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” on page 36.

The following table shows the estimated net proved oil and natural gas reserves of the principal fields located in the Partnership Properties, based on a reserve report prepared by Miller & Lents, Ltd., our independent petroleum engineers, as of June 30, 2010, and certain unaudited information regarding production and sales of oil and natural gas with respect to such properties. Our ten principal fields detailed below represent approximately 81% of our total estimated net proved reserves as of June 30, 2010, 75% of our average daily net production for the nine months ended September 30, 2010 and 90% of our standardized measure as of June 30, 2010. Please read “Risk Factors” beginning on page 29 and

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“Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 112 in evaluating the material presented below.


												Pro Forma
												Average Net
												Production
												For the Nine
	Estimated Net Proved											Months Ended					Average
	Reserves											September 30,					Reserve-
						% Oil						2010					to-		Standardized
			% Proved			and			% of					% of			Production		Measure		% of
	MBoe		Developed			NGLs			Total			(Boe/d)		Total			Ratio		(1)(2)		Total
																	(years)		(in millions)

Permian Basin Fields:
Fuhrman		11,142		44	%		94	%		38	%		907		18	%		33.7	$	195.0		42	%
Cowden North		2,460		83	%		94	%		8	%		518		10	%		13.0	$	46.5		10	%
Wasson		1,423		38	%		100	%		5	%		158		3	%		24.7	$	27.2		6	%
North Westbrook		480		66	%		100	%		2	%		96		7	%		8.3	$	14.8		3	%
Vacuum		1,067		80	%		80	%		4	%		352		2	%		13.7	$	13.9		3	%
Other		1,227		84	%		39	%		4	%		311		6	%		10.8	$	11.0		2	%

Total Permian Basin Fields		17,799		54	%		90	%		60	%		2,342		45	%		20.8	$	308.4		66	%

Ark-La-Tex Fields:
Shongaloo		4,709		100	%		30	%		16	%		1,088		21	%		11.9	$	50.9		11	%
Dorcheat		841		96	%		86	%		3	%		147		3	%		15.7	$	18.8		4	%
Other		2,371		52	%		14	%		8	%		508		10	%		12.8		17.1		4	%

Total Ark-La-Tex Fields		7,922		85	%		31	%		27	%		1,742		34	%		12.5	$	86.8		19	%

Mid-Continent Fields:
Calumet		703		100	%		97	%		2	%		205		4	%		9.4	$	13.5		3	%
Other		1,452		100	%		22	%		5	%		373		7	%		10.7	$	13.8		3	%

Total Mid-Continent Fields		2,155		100	%		47	%		7	%		578		11	%		10.2	$	27.3		6	%

Gulf Coast Fields:
Jay		550		92	%		100	%		2	%		208		4	%		7.2	$	29.8		6	%
Big Escambia Creek		660		100	%		73	%		2	%		193		4	%		9.4	$	10.1		2	%
Other		567		100	%		4	%		2	%		120		2	%		12.9	$	4.9		1	%

Total Gulf Coast Fields		1,777		98	%		59	%		6	%		522		10	%		9.3	$	44.8		10	%

*All Fields*		29,653		68	%		69	%		100	%		5,184		100	%		15.7	$	467.3		100	%


(1)		Standardized measure is calculated in accordance with Statement of Financial Accounting Standards 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. 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.

(2)		Our estimated net proved reserves and standardized measure were computed by applying average trailing twelve-month index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable 12-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

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		received at the wellhead. The average trailing 12-month index prices were $75.76/Bbl for oil and $4.10/MMBtu for natural gas for the twelve months ended June 30, 2010.

(3)		This pro forma production reflects an 8.05% overriding royalty interest in the Fund’s oil production from the Jay Field for the nine months ended September 30, 2010.

The following table shows 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.


	% Depletion
	Oil		Gas		NGL		Total
Partnership Properties(1)
Permian Basin		13.8%		3.3%		9.6%		12.2%
Ark-La-Tex		4.8%		16.0%		5.7%		7.5%
Mid-Continent		9.7%		6.2%		0.0%		6.7%
Gulf Coast		9.3%		4.9%		11.9%		10.2%

Total		13.3%		5.7%		8.3%		11.0%

Fund Retained Properties(1)
Permian Basin		11.7%		53.7%		0.0%		19.8%
Ark-La-Tex		20.0%		27.7%		0.0%		26.8%
Mid-Continent		7.9%		8.8%		38.9%		10.3%
Gulf Coast		1.7%		2.9%		12.1%		2.2%

Total		5.6%		25.6%		22.3%		11.0%


(1)		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.

Summary of Oil and Natural Gas Properties and Projects

The Permian Basin Area. As of June 30, 2010, approximately 60% of our estimated proved reserves and approximately 45% of our average daily net production for the nine months ended September 30, 2010 were located in the Permian Basin. The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States, extending over 100,000 square miles in West Texas and southeast New Mexico, and has produced over 24 billion barrels of oil since its discovery in 1921. The Permian Basin is characterized by oil and natural gas fields with long production histories, multiple producing formations and low rates of production decline. Because of the large original oil in place, we believe that many fields across the basin are ideal candidates for secondary and tertiary recovery techniques.

Major fields in the Permian Basin Area that are being produced under waterflood include Fuhrman field, Cowden North field, Wasson field, North Westbrook field and Vacuum field. These fields comprise 93% of our proved reserves in the Permian Basin Area based on our reserve report dated June 30, 2010. Please read “— Oil Recovery Overview” beginning on page 155.

We own a 19% average working interest across 1,661 gross (313 net) wells and operate approximately 80% of our properties in the Permian Basin. Based on standardized measure, however, our value-weighted-average working interest on our properties in the Permian Basin was approximately 77%. Our wells in this area produce oil and natural gas from various formations at depths from approximately 4,000 to 11,000 feet. We plan to drill 20 gross (19 net) operated and 84 gross (3 net) non-operated development wells in 2011 and 2012 at an estimated cost to us of $25.1 million. Operations in the area typically result in long-lived reserves, high drilling success rates and predictable declines, often resulting in average reserve-to-production ratios in excess of 20 years. Once drilled and completed, producing

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wells in the Permian Basin generally do not require any capital expenditures and historically have had minimal operating and maintenance requirements. Producing wells are on a tight well spacing, in the range of 10 to 20 acres in the waterflood areas. Our estimated proved reserves for our Permian Basin properties as of June 30, 2010 totaled 17,799 MBoe. For the nine months ended September 30, 2010, our Permian Basin properties produced a net average of 2,342 Boe/d at an average lifting cost of $18.16/Boe. Our Permian Basin properties have a proved developed producing production decline rate of approximately 8% per year over the next ten years and a reserve-to-production ratio of approximately 21 years based on our reserve report dated June 30, 2010. We expect to spend $71.4 million to convert our proved undeveloped reserves in the Permian Basin to proved developed producing reserves based on our reserve report dated June 30, 2010.

Fuhrman Field. The Fuhrman Field is an oil-weighted field located in Andrews County, Texas. The key producing lease in the field is Fuhrman-Mascho. Since its discovery in 1937, the field has produced approximately 26 MMBoe. Production from the field is primarily from the San Andres formation at an average depth of approximately 4,600 feet. We operate 138 gross (138 net) producing wells in the field with an average working interest of 100%. As of June 30, 2010, our properties in the field contained 11,142 MBoe of estimated net proved reserves and generated average net production of 907 Boe/d for the nine months ended September 30, 2010. The Fuhrman Field has been under waterflood since 1965 and prior operators commenced infill drilling to 20-acre spacing during the late 1970s and early 1980s. Following the initiation of the waterflood project in 1974, production from the field increased by approximately 200% over a ten-year period, and then returned to a natural state of decline. Infill drilling on ten-acre spacing commenced in 2002 on the Columbus Gray lease, resulting in a production increase of more than 200% over the following eight-year period. We have currently identified 42 ten-acre infill drilling locations at an aggregate estimated cost to us of approximately $51.7 million through 2015 and three waterflood projects in Columbus Gray sections 19, 21 and 22.

Cowden North Field. The Cowden North Field is an oil-weighted field located in Ector County, Texas. Since its discovery in 1930, the field has produced approximately 407 MMBoe. Production from the Cowden North Field is primarily from the Grayburg-San Andres formation at an average depth of approximately 4,300 feet. We operate 45 gross (41 net) producing wells in the East Cowden Grayburg Unit with an average working interest of 92%. We have a small working interest in an additional 661 gross (2 net) wells in the Cowden North Field. As of June 30, 2010, our properties in the field contained 2,460 MBoe of estimated net proved reserves and generated average net production of 518 Boe/d for the nine months ended September 30, 2010. The Cowden North Field has been under waterflood since 1967, and prior operators commenced infill drilling to 20-acre spacing during the 1980s. Following the initiation of the East Cowden Grayburg Unit waterflood project in 1974, production from the field increased by approximately 400% over a ten-year period, and then returned to a natural state of decline. Infill drilling to 10-acre well spacing commenced in 2002. Our interest in the Cowden North Field will be subject to: (i) a negative covenant prohibiting us from implementing a CO₂ recovery project in the field and (ii) an agreement with the Fund that will allow the Fund to implement, at its cost, a CO₂ recovery project, with the consent of the board of directors of our general partner, in exchange for the right to receive a share of the incremental production attributable to the injected CO₂ on such terms as may be agreed to by the board of directors of our general partner and approved by our conflicts committee.

Wasson Field. The Wasson Field is an oil-weighted field located in Yoakum County, Texas and Gaines County, Texas. Since its discovery in 1936, the field has produced approximately 23 MMBoe. Production from the Wasson Field is primarily from the Clearfork and Glorieta formations at an average depth of approximately 8,700 feet. The field is operated by Occidental Petroleum Corporation, and we own a non-operated average working interest of 5% in 89 gross (4 net) producing wells. As of June 30, 2010, our properties in the field contained 1,423 MBoe of estimated net proved reserves and generated average net production of 158 Boe/d for the nine months ended September 30, 2010. Surrounding fields, as well as portions of the Wasson Field, have been under waterflood since 1960. Following the initiation of the waterflood project in 1982, production from the field increased by approximately 200% over a five-

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year period, and then returned to a natural state of decline. Prior operators commenced infill drilling from 40-acre to 20-acre spacing beginning in 2005, but the project was not ultimately completed. We intend to complete the down-spacing at a future date and have currently identified 42 gross (4 net) infill drilling locations that we plan to undertake over the next 2 years at an estimated cost to us of $2.7 million.

North Westbrook Field. The North Westbrook Field is an oil-weighted field located in Mitchell County, Texas. Since its discovery in 1920, the field has produced approximately 44 MMBoe. Production from the North Westbrook Field is primarily from the Middle Clearfork formation at depths ranging from approximately 2,850 to 3,075 feet. The field is operated by Energen and we own a non-operated average working interest of 2% in 449 gross (9 net) producing wells. As of June 30, 2010, our properties in the field contained 480 MBoe of estimated net proved reserves and generated average net production of 96 Boe/d for the nine months ended September 30, 2010. We have currently identified 140 gross (3 net) infill drilling locations that we expect will be drilled in the next 2 years at an estimated cost to us of $1.0 million.

Vacuum Field. The Vacuum Field is located in Lea County, New Mexico. The Vacuum Field consists of two fields: the Vacuum Field, discovered in 1929, and the Glorieta West Field, discovered in 1963. Since the discovery of the Vacuum Field, the combined fields have produced approximately 99 MMBoe. Production from the Vacuum Field is primarily from the Grayburg-San Andres lime and Glorieta sand formations at depths ranging from approximately 4,600 to 6,300 feet. Our properties in the field are operated by Chevron, XTO and us. We own a working interest averaging 3% across 124 gross (3 net) producing wells. As of June 30, 2010, our properties in the field contained 1,067 MBoe of estimated net proved reserves and generated average net production of 352 Boe/d for the nine months ended September 30, 2010. The Central Vacuum unit is currently under tertiary recovery via CO₂ injection, which began in 1997, while the North Vacuum unit is currently under secondary recovery via waterflood.

The Ark-La-Tex Area. As of June 30, 2010, approximately 27% of our estimated proved reserves and approximately 34% of our average daily net production for the nine months ended September 30, 2010 was located in the Ark-La-Tex area. The Ark-La-Tex area has a long productive history, which started in 1929 with the discovery of the East Texas Field. To date, more than 190,000 wells have been drilled in the Ark-La-Tex area, with over 100,000 wells still producing.

Operations in the area typically result in long-lived reserves, high drilling success rates and predictable declines. Once drilled and completed, operating and maintenance requirements for producing wells in the Ark-La-Tex area have historically been minimal, and little, if any, capital expenditures are generally required.

We own a 56% average working interest across 225 gross (125 net) wells and operate approximately 99% of our properties in the Ark-La-Tex area. Based on standardized measure, however, our value-weighted-average working interest on these properties was approximately 76% based on our reserve report dated June 30, 2010. These wells produce oil and natural gas from various formations at depths ranging from 6,500 to 11,500 feet. We have no near term development drilling plans in this area. Our estimated proved reserves as of June 30, 2010 totaled 7,922 MBoe. For the nine months ended September 30, 2010, our Ark-La-Tex properties produced an average of 1,742 Boe/d at an average lifting cost of $6.83/Boe. Our Ark-La-Tex properties have a proved developed producing production decline rate of approximately 9% per year over the next ten years and a reserve-to-production ratio of approximately 13 years based on our reserve report dated June 30, 2010. We expect to spend $10.0 million to convert our proved undeveloped reserves in the Ark-La-Tex Area to proved developed producing reserves based on our reserve report dated June 30, 2010.

Shongaloo Field. The Shongaloo Field is an oil and natural gas field located along the Arkansas and Louisiana border. Since its discovery in 1988, the field has produced over 23 MMBoe. Production from the Shongaloo Field is primarily from the Haynesville Sand formation at an average depth of approximately 10,000 feet. There are a limited number of wells that produce from the Cotton Valley formation at approximately 8,000 feet and the Smackover formation at approximately 11,000 feet. We operate 75 gross (67 net) producing wells in the field with an average working interest of 89%. As of

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June 30, 2010, our properties in the field contained 4,709 MBoe of estimated net proved reserves and generated average net production of 1,088 Boe/d for the nine months ended September 30, 2010. We have mitigated the production decline on our properties in the Shongaloo Field through the implementation of artificial lift and are currently evaluating numerous additional artificial lift opportunities.

Dorcheat Macedonia Field. The Dorcheat Macedonia Field is an oil-weighted field located in Columbia County, Arkansas. Since its discovery in 1939, the field has produced approximately 6 MMBoe. Production from the field is primarily from the Cotton Valley and Smackover formations at an average depth of approximately 6,500 and 9,000 feet, respectively. We operate 20 gross (18 net) producing wells in the field with an average working interest of 90%. As of June 30, 2010, our properties in the field contained 841 MBoe of estimated net proved reserves and generated average net production of 147 Boe/d for the nine months ended September 30, 2010. We have mitigated the production decline in the Dorcheat Macedonia Field through workovers and recompletions of several wells. We expect that development activity of the Dorcheat Macedonia Field will consist of 3 gross (2 net) additional recompletions in the Cotton Valley formation.

The Mid-Continent Area. As of June 30, 2010, approximately 7% of our estimated proved reserves and approximately 11% of our average daily net production for the nine months ended September 30, 2010 were located in the Mid-Continent area. The Mid-Continent area is characterized by stratigraphic plays with multiple, stacked pay zones and more complex geology than our other operating areas. Similar to our other operating areas, the Mid-Continent area contains a number of fields with long production histories.

We own a 46% average working interest across 199 gross (92 net) wells and operate approximately 68% of our properties in the Mid-Continent area. Based on standardized measure, however, our value-weighted-average working interest on these properties was approximately 38% based on our reserve report dated June 30, 2010. Our estimated proved reserves for our Mid-Continent area properties as of June 30, 2010 were 2,156 MBoe. For the nine months ended September 30, 2010, our Mid-Continent properties produced an average of 578 Boe/d at an average lifting cost of $13.84/Boe. Our Mid-Continent properties have a proved developed producing production decline rate of approximately 10% per year over the next ten years and a reserve-to-production ratio of approximately 10 years based on our reserve report dated June 30, 2010.

Calumet Field. The Calumet Cottage Grove Unit, which only covers the Cottage Grove formation, is an oil-weighted field located in Canadian County, Oklahoma. Since its discovery in 1960, the field has produced approximately 10 MMBoe. Production from the Cottage Grove formation is at an average depth of approximately 8,100 feet. The Calumet field is being produced under waterflood and comprises 33% of our proved reserves in the Mid-Continent area based on our reserve report dated June 30, 2010. Please read “— Oil Recovery Overview” beginning on page 155. We operate 61 gross (33 net) producing wells in the field with an average working interest of 54%. As of June 30, 2010, our properties in the field contained 703 MBoe of estimated net proved reserves and generated average net production of 205 Boe/d for the nine months ended September 30, 2010. Current efforts for this recently acquired waterflood property are focused on reducing operating costs by improving the displacement efficiency of the reinjected water.

The Gulf Coast Area. Our Gulf Coast area is primarily comprised of the Jay Field in Florida and the Big Escambia Creek Field in Alabama. As of June 30, 2010, approximately 6% of our estimated proved reserves and approximately 10% of our average daily net production for the nine months ended September 30, 2010 were located in the Gulf Coast area. These large legacy fields, which have been producing since the 1970s, are characterized by relatively stable production profiles and long production histories.

We own a 29% average working interest across 14 gross (4 net) wells and operate approximately 99% of our properties in the Gulf Coast area. Based on standardized measure, however, our value-weighted-average working interest on these properties was approximately 23% based on our reserve

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report dated June 30, 2010. These wells produce from various formations, as deep as approximately 15,000 feet. Once drilled and completed, operating and maintenance requirements for producing wells in the Gulf Coast area have historically been relatively low.

Our estimated proved reserves as June 30, 2010 were 1,777 MBoe, including the overriding oil royalty interest in the Jay Field. Pro forma for our overriding oil royalty interest in the Jay Field for the nine months ended September 30, 2010, our Gulf Coast properties produced an average of 522 Boe/d at an average lifting cost of $7.78/Boe. Our Gulf Coast properties have a proved developed producing production decline rate of approximately 10% per year over the next ten years and a reserve-to-production ratio of approximately 9 years based on our reserve report dated June 30, 2010.

Overriding Oil Royalty Interest in Jay Field. In connection with the closing of this offering, the Fund will create and contribute an 8.05% overriding oil royalty interest on its 92% working interest in the Jay Field in Florida. This overriding oil royalty interest will not be applicable to natural gas or NGLs associated with the Jay Field operations. Estimated proved reserves associated with the overriding oil royalty interest were 550 MBbls as of June 30, 2010. Our overriding royalty interest in the Jay Field oil reserves:


	•	will entitle us to receive 8.05% of oil production volumes over the life of the Jay Field from all of the Fund’s 92% working interest in the Jay Field;

	•	does not bear any future production costs or capital expenditures associated with the reserves;

	•	is nonrecourse to the Fund (i.e., our only recourse is to the reserves acquired); and

	•	transfers title of the associated reserves to us.

The Jay Field is comprised of approximately 14,400 contiguous acres located on the Florida-Alabama state line. Since its discovery in 1970, the field has produced approximately 467 MMBoe. Production from the Jay Field is primarily from the Smackover carbonate formation at an average depth of approximately 15,000 feet. The Jay field is being produced under miscible nitrogen flood and comprises 31% of our proved reserves in the Gulf Coast area based on our reserve report dated June 30, 2010. Please read “— Oil Recovery Overview” beginning on page 155. The field had inclining production rates as of June 30, 2010 but historically had established an approximate 12% proved developed producing decline rate prior to suspension of operations in late 2008. For the nine months ended September 30, 2010, the Fund generated 394 Boe/d of net average production from its 92% working interest in the Jay Field.

Quantum Resources Management considers the primary opportunities in the Jay Field to be cost savings and development opportunities, with a goal of further reducing operating costs, improving margins and extending the effective life of the field. Quantum Resources Management operates 39 gross (36 net) producing wells in the Jay Field. The field is being produced under miscible nitrogen flood with the make-up nitrogen provided by an air separation unit owned by the Fund. All described facilities with regards to the Jay Field are operated by Quantum Resources Management on behalf of the Fund.

Production from the Jay Field was temporarily suspended in December 2008 to conduct certain necessary operations related to regulatory compliance, increasing facility runtime and improving cost performance. The original process used Nitrogen Rejection Units, or NRUs, to separate the nitrogen from the natural gas stream. During the last quarter of 2009, the facility was reconfigured for a new process that involves the reinjection of the nitrogen and natural gas stream into the reservoir, thereby eliminating the need for the NRUs, improving runtimes, reducing electric costs and increasing net injection into the reservoir.

The Jay Field currently has over 35 gross (32 net) inactive wells being evaluated for reactivation. Since restarting the field in December 2009, Quantum Resources Management has performed seven workovers and six reactivations. These combined projects have been successful and have resulted in an average increase in production of 100 Bbls/d of oil during the six months ended June 30, 2010. Additionally, average lifting costs have decreased from approximately $55 per Boe to approximately

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$33 per Boe through September 30, 2010, and we expect this number to continue to decline as field production increases.

Big Escambia Creek Field. The Big Escambia Creek Field is an oil-weighted field located in Escambia County, Alabama. Since its discovery in 1974, the field has produced over 62 MMBoe. Production from the Big Escambia Creek Field is primarily from the Jurassic Smackover formation at an average depth of approximately 14,000 feet. The field is operated by Eagle Rock Energy, and we own a non-operated average working interest of 15% in 5 gross (1 net) producing wells. As of June 30, 2010, our properties in the field contained 660 MBoe of estimated net proved reserves and generated average net production of 193 Boe/d for the nine months ended September 30, 2010.

Oil Recovery Overview

When an oil field is first produced, the oil typically is recovered as a result of natural pressure within the producing formation. The only natural force present to move the oil through the reservoir rock to the wellbore is the pressure differential between the higher pressure in the rock formation and the lower pressure in the wellbore. Various types of pumps are often used to reduce pressure in the wellbore, thereby increasing the pressure differential. At the same time, there are many factors that act to impede the flow of oil, depending on the nature of the formation and fluid properties, such as pressure, permeability, viscosity and water saturation. This stage of production, referred to as “primary recovery,” recovers only a small fraction of the oil originally in place in a producing formation.

Many, but not all, oil fields are amenable to assistance from a waterflood, a form of “secondary recovery,” which is used to maintain reservoir pressure and to help sweep oil to the wellbore. In a waterflood, some of the wells are used to inject water into the reservoir while other wells are used to produce the fluid. As the waterflood matures, the fluid produced contains increasing amounts of water and decreasing amounts of oil. Surface equipment is used to separate the oil from the water, with the oil going to pipelines or holding tanks for sale and the water being recycled to the injection facilities. Primary recovery followed by secondary recovery usually produces between 15% and 40% of the oil originally in place in a producing formation.

A third stage of oil recovery is called “tertiary recovery” or “enhanced oil recovery.” In addition to maintaining reservoir pressure, this type of recovery seeks to alter the properties of the oil in ways that facilitate production. The three major types of tertiary recovery are chemical flooding, thermal recovery (such as a steamflood) and miscible displacement involving CO₂, hydrocarbon or nitrogen injection. In a CO₂ flood, CO₂ is liquefied under high pressure and injected into the reservoir. The CO₂ then swells the oil in a way that increases the mobilization of bypassed oil while also reducing the oil’s viscosity. The lighter components of the oil vaporize into the CO₂ while the CO₂ also condenses into the oil. In this manner, the two fluids become miscible, mixing to form a homogeneous fluid that is mobile and has lower viscosity and lower interfacial tension, thus facilitating the migration of oil and natural gas to the wellbore.

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. Major fields in the Permian Basin Area that are being produced under waterflood include Fuhrman field, Cowden North field, Wasson field, North Westbrook field and Vacuum field. These fields comprise 93% of our proved reserves in the Permian Basin Area based on our reserve report dated June 30, 2010. In the Mid-Continent Area, the Calumet field is being produced under waterflood and comprises 33% of our proved reserves in the area based on our reserve report dated June 30, 2010. The Jay field, in the Gulf Coast Area, is being produced under miscible nitrogen flood and comprises 31% of our proved reserves in the area based on our reserve report dated June 30, 2010. Please read “Risk Factors — Risks Related to Our Business — 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” on page 37.

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Oil and Natural Gas Data and Operations — Partnership Properties

Internal Controls

Our proved reserves are estimated at the well or unit level and compiled for reporting purposes by Quantum Resources Management’s corporate reservoir engineering staff, all of whom are independent of Quantum Resources Management operating teams. Quantum Resources Management maintains internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interacts with Quantum Resources Management’s internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by our senior management on a semi-annual basis. Following the consummation of this offering, we anticipate that the audit committee of our general partner’s board of directors will conduct a similar review on a semi-annual basis. We expect to have our reserve estimates evaluated by our independent third-party reserve engineers, Miller & Lents, Ltd., at least annually.

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

Technology Used to Establish Proved Reserves

Under the SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and Miller & Lents, Ltd. employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Qualifications of Responsible Technical Persons

Internal Quantum Resources Management Person. Kyle Schultz, Senior Exploitation Advisor, is the technical person primarily responsible for overseeing the preparation of our reserves estimates.

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Mr. Schultz is also responsible for liaison with and oversight of our third-party reserve engineer. Mr. Schultz has over 31 years of industry experience with positions of increasing responsibility in engineering and evaluations with companies such as ExxonMobil, XTO Energy and Encore Acquisition Company. He holds a Bachelor of Science degree in Chemical Engineering.

Miller & Lents. Miller & Lents, Ltd., or MLL, is an independent oil and natural gas consulting firm. No director, officer, or key employee of MLL has any financial ownership in Quantum Resources Management, the Fund or any of their respective affiliates. MLL’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and MLL has not performed other work for Quantum Resources Management, the Fund or us that would affect its objectivity. The engineering audit presented in the Miller and Lents, Ltd. report was overseen by Mr. Roy Lee Comer, Jr. Mr. Comer is an experienced reservoir engineer having been a practicing petroleum engineer since June of 1981. He has more than 20 years of experience in reserves evaluation. He has a Bachelors of Science Degree in Chemical Engineering from the Ohio State University and is a Registered Professional Engineer in the State of Texas.

Estimated Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves attributable to the Partnership Properties and the standardized measure amounts associated with the estimated proved reserves attributable to the Partnership Properties as of December 31, 2009, based on reserve reports prepared by our internal reserve engineers, and as of June 30, 2010, based on reserve reports prepared by Miller & Lents, Ltd., our independent reserve engineers. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.


	Partnership Properties
	As of		As of
	December 31,		June 30,
	2009		2010

Reserve Data(1):
Estimated proved reserves:
Oil (MBbls)		20,108		19,050
NGLs (MBbls)		1,629		1,488
Natural gas (MMcf)		56,330		54,688

Total estimated proved reserves (MBoe)(2)		31,125		29,653
Estimated proved developed reserves:
Oil (MBbls)		12,798		11,380
NGLs (MBbls)		1,579		1,441
Natural gas (MMcf)		46,498		44,700

Total estimated proved developed reserves (MBoe)(2)		22,127		20,271
Estimated proved undeveloped reserves:
Oil (MBbls)		7,310		7,670
NGLs (MBbls)		50		47
Natural gas (MMcf)		9,832		9,988

Total estimated proved undeveloped reserves (MBoe)(2)		8,998		9,382
Standardized Measure (in millions)(3)	$	360.1	$	467.3


(1)		Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $61.18/Bbl for oil and NGLs and $3.87/MMBtu for natural gas at December 31, 2009 and $75.76/Bbl for oil and NGLs and $4.10/MMBtu for natural gas at June 30,

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		2010. 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 $71.52 per Bbl, $3.99 per Mcf and $44.46 per Bbl, respectively.

(2)		One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGL’s based on a rough energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.

(3)		Standardized measure is calculated in accordance with Statement of Financial Accounting Standards 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. 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.

The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, please read “Risk Factors — Risks Related to Our Business — Our Estimated Proved Reserves 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 Reserves” on page 36.

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

Development of Proved Undeveloped Reserves

None of our proved undeveloped reserves at June 30, 2010 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, our predecessor’s drilling and development programs were substantially funded from its cash flow from operations. Our expectation is to continue to fund our drilling and development programs primarily from our cash flow from operations. Based on our current expectations of our cash flows and drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations and our expansions, extensions and processing of our waterfloods in the next five years from our cash flow from operations and, if needed, our new credit facility. For a more detailed discussion of our pro forma liquidity position, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources” on page 122.

Because our operations and properties will not be separate from those of our predecessor until the closing of this offering, we do not yet have a record of converting our proved undeveloped reserves to proved developed reserves. For more information about our predecessor’s historical costs associated with the development of proved undeveloped reserves, please read Note 15 to the Historical Consolidated Financial Statements of QA Holdings, LP as of and for the Year Ended December 31, 2009.

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Production, Revenues and Price History

The following table sets forth information regarding combined net production of oil and natural gas and certain price and cost information (i) of our predecessor on a historical basis and (ii) attributable to the Partnership Properties on a pro forma basis for each of the periods presented:


	Our Predecessor						Partnership Properties
	Year Ended						Year Ended		Nine Months Ended
	December 31,						December 31,		September 30,
	2007		2008		2009		2009		2009		2010

Production and operating data:
Net production volumes(1):
Oil (MBbls)		1,668		1,753		739		931		700		689
Natural gas (MMcf)		5,476		5,590		5,359		5,151		3,907		3,687
NGLs (MBbls)		121		139		207		137		101		111

Total (MBoe)		2,701		2,824		1,838		1,927		1,452		1,415
Average net production (Boe/d)		7,401		7,736		5,038		5,280		5,319		5,184
Average sales price:(2)
Oil (per Bbl)	$	71.94	$	97.40	$	55.74	$	56.41	$	51.46	$	74.35
Natural gas (per Mcf)	$	6.81	$	9.62	$	4.03	$	3.84	$	3.67	$	4.85
NGLs (per Bbl)	$	50.29	$	64.70	$	34.02	$	33.31	$	29.57	$	46.86
Average price per Boe	$	60.49	$	82.68	$	37.99	$	39.91	$	36.74	$	52.51
Average unit costs per Boe:
Oil and natural gas production expenses	$	28.79	$	32.02	$	18.13	$	12.34	$	11.63	$	10.77
Production taxes	$	4.80	$	5.16	$	4.13	$	2.99	$	1.98	$	2.35
Management fees	$	4.25	$	4.26	$	6.54	$	—	$	—	$	—
General and administrative and other	$	7.66	$	5.26	$	10.59	$	5.85	$	6.73	$	8.71
Depletion, depreciation and amortization	$	15.88	$	17.46	$	9.24	$	12.66	$	12.63	$	12.96


(1)		The Fuhrman Field constituted approximately 38% of our estimated proved reserves as of June 30, 2010. Our predecessor’s production from the Fuhrman Field was 340, 342 and 347 MBoe, for the years ended December 31, 2007, 2008 and 2009, respectively. The 2007 production was comprised of 313 MBbls of oil, 161 MMcf of natural gas and no NGLs. The 2008 production was comprised of 320 MBbls of oil, 134 MMcf of natural gas and no NGLs. The 2009 production was comprised of 325 MBbls of oil, 133 MMcf of natural gas and no NGLs.

(2)		Prices do not include the effects of derivative cash settlements.

Present Drilling and Other Exploratory and Development Activities

Drilling Activities. As of September 30, 2010, Quantum Resources Management was not conducting any drilling activities on the Partnership Properties.

Other Exploratory and Development Activities. As of September 30, 2010, we were in the process of completing the installation of additional waterflood facilities in section 22 of the Columbus Gray lease to activate infill drilling wells completed in 2009.

Predecessor Drilling and Other Exploratory and Development Activities

Because our operations and properties will not be separate from those of our predecessor until the closing of this offering, we do not yet have a record of drilling or other exploratory or development

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activities. Our general partner will determine the amount and timing of our exploratory or development activities and Quantum Resources Management will execute our program in addition to continuing to execute our predecessor’s exploratory and development program. For more information about our predecessor’s historical exploratory and development activities, please read ‘‘— Oil and Natural Gas Data and Operations — Our Predecessor — Drilling Activities” on page 161. Our predecessor’s historical exploratory and development activities should not be considered indicative of the future performance of our program.

Productive Wells

The following table sets forth information at September 30, 2010 relating to the productive wells in which we, on a pro forma basis, owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells.


	Oil				Natural Gas
	Gross		Net		Gross		Net

Operated		386		338		173		141
Non-operated		1,357		26		183		29

Total		1,743		364		356		170

Developed Acreage

The following table sets forth information as of September 30, 2010 relating to our pro forma leasehold acreage. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of September 30, 2010, all of our leasehold acreage was held by production.


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

Permian Basin		29,514		22,880
Mid-Continent		33,622		17,106
Ark-La-Tex		31,535		17,916
Gulf Coast		16,990		14,894

Total		111,661		72,796


(1)		Developed acres are acres spaced or assigned to productive wells or wells capable of production.

(2)		A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(3)		A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Delivery Commitments

We will have no delivery commitments with respect to our production upon the closing of this offering and the contribution of the Partnership Properties to us.

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Oil and Natural Gas Data and Operations — Our Predecessor

Drilling Activities

The following table sets forth information with respect to wells drilled and completed by our predecessor during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.


	Year Ended December 31,
	2007				2008				2009
	Gross		Net		Gross		Net		Gross		Net

Development wells:
Productive		104		15.3		77		11.9		123		2.5
Dry		—		—		2		1.9		—		—
Exploratory wells:
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total wells:
Productive		104		15.3		77		11.9		123		2.5
Dry		—		—		2		1.9		—		—

Total		104		15.3		79		13.8		123		2.5

Operations

General

We operated approximately 83% of our assets as determined by value, based on standardized measure as of June 30, 2010 on a pro forma basis. We design and manage the development, recompletion or workover for all of the wells we operate and supervise operation and maintenance activities. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on the properties we operate. Independent contractors provide all the equipment and personnel associated with these activities. Pursuant to our general partner’s services agreement, Quantum Resources Management will provide certain administrative services to us. Quantum Resources Management employs production and reservoir engineers, geologists and other specialists, as well as field personnel. Please read “— Administrative Services Fee” on page 161 and “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement” on page 188. We charge the non-operating partners a contractual administrative overhead charge for operating the wells. Some of our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies.

Administrative Services Fee

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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. 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 paid Quantum Resources Management pursuant to the services agreement, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement” on page 188.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on the Partnership Properties range from less than 1% to 36%, resulting in a net revenue interest to us ranging from 64% to 100%, or 85% on average. Most of our leases are held by production and do not require lease rental payments.

Marketing and Major Customers

For the year ended December 31, 2009, purchases by Shell Trading US Company, or Shell, Sunoco Inc. R&M, or Sunoco, and Plains Marketing, L.P., or Plains, accounted for 24%, 12% and 10%, respectively, of our predecessor’s total sales revenues. Shell, Sunoco, and Plains purchase the oil production from our predecessor pursuant to existing marketing agreements with terms that are currently on “evergreen” status and renew on a month-to-month basis until either party gives 30-day advance written notice of non-renewal.

If we were to lose any one of our customers, the loss could temporarily delay production and sale of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether, the loss of such could have a detrimental effect on our production volumes in general and on our ability to find substitute customers to purchase our production volumes.

Hedging Activities

We intend to enter into commodity derivative contracts with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. All of our current commodity derivative contracts are fixed price swaps with NYMEX prices. For a more detailed discussion of our hedging activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources” on page 122 and “— Pro Forma Quantitative and Qualitative Disclosure About Market Risk” on page 125.

Competition

We operate in a highly competitive environment for acquiring properties and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry.

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We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment. In recent years, the United States onshore oil and natural gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation programs.

Title to Properties

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the titles to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, resulting in seasonal fluctuations in the price we receive for our natural gas production. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation.

Environmental Matters and Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and (v) impose substantial liabilities for pollution resulting from drilling and

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production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of corrective or remedial obligations, and the issuance of orders enjoining performance of some or all of our operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that this trend will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste

The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, or CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, neighboring landowners and other third-parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

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We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination

Water Discharges

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure, or SPCC, plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws required individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended, or OPA, amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States.

It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate natural gas production. Due to public concerns raised regarding the potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. In particular, the U.S. Senate and House of Representatives are currently considering bills entitled, the “Fracturing Responsibility and Awareness of Chemicals Act,” or the FRAC Act, to amend the federal Safe Drinking Water Act, or the SDWA, to repeal an exemption from regulation for hydraulic fracturing. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities, requiring hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process. 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 hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process 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

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our exploration and production activities, which could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Air Emissions

The federal Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development of oil and natural gas projects. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, we do not believe that such requirements will have a material adverse effect on our operations.

Climate Change

On December 15, 2009, the 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 Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or “PSD,” and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. In addition, in October 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. In April 2010, the EPA proposed to expand this 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.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur in areas where we operate, they could have in adverse effect on our assets and operations.

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National Environmental Policy Act

Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Currently, we have minimal exploration and production activities on federal lands. However, for those current activities as well as for future or proposed exploration and development plans on federal lands governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay the development of oil and natural gas projects.

Endangered Species Act

Additionally, environmental laws such as the Endangered Species Act, as amended, or ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and prohibits taking of endangered species. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

OSHA

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress, and the development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, we do not believe that compliance with these laws will have a material adverse impact on us.

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Drilling and Production

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:


	•	the location of wells;

	•	the method of drilling and casing wells;

	•	the surface use and restoration of properties upon which wells are drilled;

	•	the plugging and abandoning of wells; and

	•	notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of our properties. Sales of condensate and NGLs are not currently regulated and are made at market prices.

State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

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Employees

The officers of our general partner will manage our operations and activities. However, neither we, our subsidiaries, nor our general partner have employees. Immediately prior to 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 perform services for us, including the operation of our properties. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement” on page 188.

As of September 30, 2010, Quantum Resources Management had 187 employees, including 16 engineers, 3 geologists and 6 land professionals. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that Quantum Resources Management’s relations with its employees are satisfactory. We will also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed.

Offices

For our principal offices, we currently lease approximately 40,000 square feet of office space in Houston, Texas at 5 Houston Center, 1401 McKinney Street, Suite 2400, Houston, Texas 77010. Our lease expires on December 31, 2012.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

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MANAGEMENT

Management of QR Energy, LP

QRE GP, LLC, our general partner, will manage our operations and activities on our behalf. Our general partner is owned by entities that are controlled by affiliates of Quantum Energy Partners and the Fund. All of our executive management personnel are employees of Quantum Resources Management, and will devote their time as needed to conduct our business and affairs.

Immediately prior to the closing of this offering, our general partner will enter into a services agreement with Quantum Resources Management. 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 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. The services agreement provides that employees of Quantum Resources Management (including the persons who are executive officers of our general partner) will devote such portion of their time as may be reasonable and necessary for the operation of our business. It is anticipated that certain of the executive officers of our general partner will devote significantly less than a majority of their time to our business for the foreseeable future.

Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. However, our partnership agreement contains provisions that reduce the fiduciary duties that our general partner owes to our unitholders. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” beginning on page 201. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it. Except as described in “The Partnership Agreement — Limited Voting Rights” on page 207 and subject to its fiduciary duty to act in good faith, our general partner will have exclusive management power over our business and affairs.

Our general partner has a board of directors that oversees its management, operations and activities. Upon the closing of this offering, the board of directors of our general partner will have one member who is not an officer or employee of our general partner or its affiliates, and is otherwise independent, of Quantum Resources Management and the Fund and their affiliates, including our general partner. This director, to whom we refer to as an independent director, must meet the independence standards established by the NYSE and SEC rules. Within one year of the closing of this offering, the board of directors of our general partner will have at least three independent directors to serve on the audit committee. The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee.

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At least one independent member of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board of directors believes may involve conflicts of interest and which it determines to submit to the conflicts committee for review. Pursuant to the regulations of the NYSE, the board of directors of our general partner 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. Under our partnership agreement, our conflicts committee has responsibility for (i) approving the board of directors of our general partner’s determination of the fair market value of our assets (other than our estimated oil and natural gas reserves and our commodity derivative contracts) in connection with the determination of our management incentive fee base; (ii) approving the amount of estimated maintenance capital expenditures deducted from operating surplus; and (iii) the approval of the allocation of capital expenditures between maintenance capital expenditures, investment capital expenditures and growth capital expenditures. Other than these enumerated responsibilities, 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. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence standards established by the NYSE Listed Company Manual and the Securities Exchange Act of 1934 to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Please read “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest” on page 193.

In addition, within one year of the closing of this offering, our general partner will have an audit committee of at least three directors who meet the independence and experience standards established by the NYSE Listed Company Manual and the Securities Exchange Act of 1934. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

Generally, the executive officers of our general partner listed below will allocate their time between managing our business and affairs and the business and affairs of Quantum Resources Management and the other entities Quantum Resources Management may serve. The executive officers of our general partner may face a conflict regarding the allocation of their time between our business and the other business interests of Quantum Resources Management and the other entities Quantum Resources Management may serve. Quantum Resources Management intends to cause the executive officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs although it is anticipated that the executive officers of our general partner will devote significantly less than a majority of their time to our business for the foreseeable future. We will also use a significant number of other employees of Quantum Resources Management to operate our business and provide us with general and administrative services. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement” on page 188.

Board Leadership Structure and Role in Risk Oversight

Leadership of our general partner’s board of directors is vested in a Chairman of the Board. Although our Chief Executive Officer currently does not serve as Chairman of the board of directors of

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our general partner, we currently have no policy prohibiting our current or any future chief executive officer from serving as Chairman of the Board. The board of directors, in recognizing the importance of the board of directors having the ability to operate independently, determined that separating the roles of Chairman of the Board and Chief Executive Officer is advantageous for us and our unitholders. Our general partner’s board of directors has also determined that having the Chief Executive Officer serve as a director enhances understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations, and ultimately improves the ability of the board of directors to perform its oversight role.

The management of enterprise-level risk may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to the creation of value for our unitholders. The board of directors of our general partner has delegated to management the primary responsibility for enterprise-level risk management, while retaining responsibility for oversight of our executive officers in that regard. Our executive officers will offer an enterprise-level risk assessment to the board of directors at least once every year.

Directors and Executive Officers

The following table sets forth certain information regarding the current directors and executive officers of our general partner. Directors are elected for one-year terms.


Name	Age		Position with Our General Partner

Alan L. Smith		48	Chief Executive Officer and Director
John H. Campbell, Jr.		53	President, Chief Operating Officer and Director
Cedric W. Burgher		50	Chief Financial Officer
Gregory S. Roden		52	Vice President, Secretary and General Counsel
Howard K. Selzer		54	Chief Accounting Officer
Donald D. Wolf		67	Chairman of the Board
Toby R. Neugebauer		39	Director
S. Wil VanLoh, Jr.		40	Director
Donald E. Powell		68	Director Nominee

Our general partner’s directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our general partner’s directors or executive officers. In selecting and appointing directors to the board of directors, the owners of our general partner do not intend to apply a formal diversity policy or set of guidelines. However, when appointing new directors, the owners of our general partner will consider each individual director’s qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the board of directors as a whole.

Alan L. Smith is the Chief Executive Officer and a member of the board of directors of our general partner. Mr. Smith also serves as a Venture Partner with Quantum Energy Partners. Prior to becoming the Chief Executive Officer of Quantum Resources Management in 2009, Mr. Smith served as a Managing Director with Quantum Energy Partners and as Chairman of Chalker Energy Partners II, LLC, both beginning in 2006. From 2003 until 2006, Mr. Smith served as the President and CEO of Chalker Energy Partners I, LLC, a private oil and natural gas exploration and production company he co-founded, which was funded by Quantum Energy Partners. From 2001 until 2003, Mr Smith served as the Vice President of Business Development at Ocean Energy, Inc. and from 1999 to 2001 he was the Asset Manager for an onshore business unit at Ocean Energy. Prior to 1999, Mr. Smith served in positions of increasing responsibility at XPLOR Energy, Inc., Ryder Scott Company, Burlington Resources and Vastar Resources/ARCO Oil and Gas Company. From June 2006 to June 2007, Mr. Smith served on the board

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Resources/ARCO Oil and Gas Company. From June 2006 to June 2007, Mr. Smith served on the board of directors of Linn Energy, LLC. He serves as a board member for the Southeastern Region IPAA, an advisory board member of the A&D Watch, a Hart’s publication, and also serves in an advisory capacity to the Texas Tech Department of Petroleum Engineering. We believe that Mr. Smith’s extensive experience in the energy industry and his relationships with Quantum Resources Management and Quantum Energy Partners, particularly his service as the Chief Executive Officer of Quantum Resources Management, bring important experience and skill to the board of directors.

John H. Campbell, Jr. is the President and Chief Operating Officer and a member of the board of directors of our general partner. Mr. Campbell also serves as a Managing Director with Quantum Energy Partners, a position he has held since 2003. Prior to joining Quantum Energy Partners in 2003, Mr. Campbell served as Senior Vice President Operations for North America Onshore for Ocean Energy, Inc. from 1998 to 2003, where he was responsible for the company’s extensive onshore oil and natural gas operations. He joined Ocean in 1998 from Burlington Resources, Inc. where, over a period of eleven years, he served in a variety of engineering, operational and management positions. Prior to Burlington, he was a field engineer with Schlumberger Ltd. from 1982 to 1985. Over the years, he has led the technical and capital allocation efforts for major onshore and offshore assets, as well as the evaluation of numerous property acquisitions and mergers. We believe that Mr. Campbell’s extensive experience in the energy industry, particularly his background and experience in the engineering and operational aspects of exploration and production activities, bring important experience and skill to the board of directors.

Cedric W. Burgher is the Chief Financial Officer of our general partner. Mr. Burgher served as a Managing Director of Quantum Energy Partners from 2008 until 2010. Prior to joining Quantum Energy Partners, Mr. Burgher was Senior Vice President and Chief Financial Officer of KBR, Inc., a global engineering, construction and services company, from 2005 until 2008. Prior to KBR, Mr. Burgher served as the Chief Financial Officer of Burger King Corporation, an international restaurant company, from 2004 to 2005. Mr. Burgher worked for Halliburton Company, an oilfield services company, from 2001 to 2004, most recently as the Vice President and Treasurer and, prior to that, as the Vice President of Investor Relations. He also previously held financial management positions with Enron, EOG Resources and Baker Hughes following several years in the banking industry. Mr. Burgher is a Chartered Financial Analyst (CFA).

Gregory S. Roden is the Vice President and General Counsel of our general partner. Since 2009, Mr. Roden has served as Vice President and General Counsel of Quantum Resources Management. From 2005 to 2009, Mr. Roden was Senior Counsel for Devon Energy supporting their Southern and Gulf of Mexico Divisions. From 2003 to 2005, Mr. Roden worked for BP on various LNG regasification projects in the U.S. and in support of BP’s products trading floor. Mr. Roden served as Ocean Energy’s Assistant General Counsel for Onshore Domestic Operations from 2000 to 2003. Mr. Roden commenced his legal practice in 1992 as an oil and natural gas attorney specializing in acquisitions and divestitures with Akin, Gump, Strauss, Hauer and Feld, LLP. Prior to becoming an attorney, Mr. Roden worked from 1980 to 1989 for Exxon Company USA in various natural gas production, processing, marketing and management positions.

Howard K. Selzer is the Chief Accounting Officer of our general partner. Mr. Selzer is also Chief Accounting Officer for Quantum Resources Management. His primary responsibility is to oversee all of our accounting, financial reporting, tax and audit functions. Prior to joining Quantum Resources Management in 2009, Mr. Selzer was Chief Financial Officer for Terralliance Technologies, Inc. from 2007 to 2009. From 2006 to 2007, Mr. Selzer was VP Finance and Administration of TGS-NOPEC. In addition, he served as CFO of Santos USA from 2003 to 2005. Prior to joining Santos, Mr. Selzer was with Enron Oil & Gas International, where he held the roles of Senior Director & Controller and Manager, Financial Reporting & Budgets from 1992 to 2003. Mr. Selzer worked and was most recently an International Petroleum Negotiator based in Paris, France for Elf Aquitaine from 1983 to 1992 and an International Petroleum Accountant for Cities Service Co. from 1981 to 1983. He is a Certified Public Accountant.

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Donald D. Wolf serves as the Chairman of the board of directors of our general partner. Previously, Mr. Wolf served as the Chief Executive Officer of Quantum Resources Management from 2006 until 2009 and he continues to serve as the Chief Executive Officer of the general partner of the Fund. Prior to serving as the Chief Executive Officer of Quantum Resources Management, Mr. Wolf served as President and Chief Executive Officer of Aspect Energy, LLC, from 2004 until 2006. Prior to joining Aspect, Mr. Wolf served as Chairman and Chief Executive Officer of Westport Resources Corporation from 1996 to 2004. Mr. Wolf has also served as President and Chief Operating Officer of United Meridian Corporation from 1994 to 1996; President and Chief Executive Officer of General Atlantic Resources, Inc. from 1981 to 1993; and Co-Founder and President of Terra Marine Energy Company from 1977 to 1981. He began his career in 1965 with Sun Oil Company in Calgary, Alberta, Canada, working in operations and land management. Following Sun Oil Company, he assumed land management positions with Bow Valley Exploration, Tesoro Petroleum Corp. and Southland Royalty Company from 1971 through 1977. Mr. Wolf currently serves as a director of the general partner of MarkWest Energy Partners, L.P., Enduring Resources, LLC, Laredo Petroleum, LLC, Ute Energy, LLC, and Aspect Energy, LLC. Mr. Wolf is a former director of the Independent Petroleum Association of Mountain States, or IPAMS. We believe that Mr. Wolf’s extensive experience in the energy industry, most notably in serving as Chief Executive Officer of Westport Resources Corporation for eight years, bring substantial experience and leadership skill to the board of directors.

Toby R. Neugebauer is a member of the board of directors of our general partner. Since 1998, Mr. Neugebauer has been a Managing Partner of Quantum Energy Partners, a private equity firm specializing in the energy industry which he co-founded in 1998. Prior to co-founding Quantum Energy Partners, Mr. Neugebauer co-founded Windrock Capital, Ltd., an energy investment banking firm specializing in raising private equity and providing merger, acquisition and divestiture advice for energy companies. Before co-founding Windrock Capital, Ltd. in 1994, Mr. Neugebauer was an investment banking analyst in Kidder, Peabody & Co.’s Natural Resources Group where he worked on corporate debt and equity financings, mergers and acquisitions, and other highly structured transactions for energy and energy-related companies. Mr. Neugebauer currently serves on the boards of a number of portfolio companies of Quantum Energy Partners, all of which are private energy companies. Mr. Neugebauer also serves on the board of QA Global GP, LLC, which is the entity controlling the Fund. From January through June 2006, Mr. Neugebauer served as the Chairman of the Board of Directors of Linn Energy, LLC, and he was involved in the founding of Legacy Reserves LP. Mr. Neugebauer’s extensive experience from investing in the energy industry over the past thirteen years and serving as a director for numerous private energy companies brings unique and valuable skills to the board of directors.

S. Wil VanLoh, Jr. is a member of the board of directors of our general partner. Mr. VanLoh is the President and Chief Executive Officer of Quantum Energy Partners, which he co-founded in 1998. Quantum Energy Partners manages a family of energy-focused private equity funds, with more than $5.7 billion of capital under management. Mr. VanLoh is responsible for the leadership and overall management of the firm. Additionally, he leads the firm’s investment strategy and capital allocation process, working closely with the investment team to ensure its appropriate implementation and execution. He oversees all investment activities, including origination, due diligence, transaction structuring and execution, portfolio company monitoring and support, and transaction exits. Prior to co-founding Quantum Energy Partners, Mr. VanLoh co-founded Windrock Capital, Ltd., an energy investment banking firm specializing in providing merger, acquisition, and divestiture advice to and raising private equity for energy companies. Prior to co-founding Windrock in 1994, Mr. VanLoh worked in the energy investment banking groups of Kidder, Peabody & Co. and NationsBank. Mr. VanLoh currently serves on the boards of a number of portfolio companies of Quantum Energy Partners, all of which are private energy companies. Mr. VanLoh also serves on the board of QA Global GP, LLC, which is the entity controlling the Fund. Mr. VanLoh served on the board of directors of the general partner of Legacy Reserves LP from its founding to August 1, 2007, and was also involved in the founding of Linn Energy, LLC. Mr. VanLoh has served as a board member and Treasurer of the Houston Producer’s Forum and on the Finance Committee of the Independent Petroleum Association of America (“IPAA”). We believe that Mr. VanLoh’s extensive experience, both from investing in the energy industry over the past

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thirteen years and serving as director for numerous private energy companies, brings important and valuable skills to the board of directors.

Donald E. Powell will be appointed to serve on the board of directors of our general partner upon completion of this offering. He has been a member of the board of directors of Bank of America Corporation since 2009, and a member of the board of directors of Stone Energy Corporation since 2008. Mr. Powell served as the Federal Coordinator of Gulf Coast Rebuilding from 2005 until 2008. Prior to 2005, Mr. Powell was the 18th Chairman of the Federal Deposit Insurance Corporation, where he served from 2001 until 2005. He previously served as President and Chief Executive Officer of the First National Bank of Amarillo, where he started his banking career in 1971. Mr. Powell was selected to serve as a director because of his vast financial experience, which brings a unique and valuable experience to the Board.

Reimbursement of Expenses of Our General Partner

Immediately prior to the closing of this offering, our general partner will enter into a services agreement with Quantum Resources Management. 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. 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 to Quantum Resources Management. 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 by Quantum Resources Management to its affiliates. 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 that Quantum Resources Management will be entitled to receive to the services agreement, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement” on page 188.

Executive Compensation

We and our general partner were formed in September 2010. As such, our general partner did not accrue any obligations with respect to executive compensation for its directors and executive officers for the fiscal year ended December 31, 2009, or for any prior periods. Accordingly, we are not presenting any compensation for historical periods. We have not paid or accrued any amounts for executive compensation for the 2009 fiscal year.

The executive officers of our general partner will be employed by Quantum Resources Management and will manage the day-to-day affairs of our business. Mr. Burgher will be the dedicated Chief Financial Officer of our general partner and will devote all of his time to our business once he ceases to serve as interim Chief Financial Officer for the Fund following the hiring of a permanent replacement. We expect that the other executive officers of our general partner will devote their time to

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our business as follows: Messrs. Campbell and Smith will devote approximately 25% of their time; Mr. Roden will devote approximately 30% of his time; and Mr. Selzer will devote approximately 50% of his time. The amount of time that each of our executive officers devote to our business will be subject to change depending on our activities, the Fund’s activities and any acquisitions or dispositions made by us or the Fund.

Because the executive officers of our general partner are or will be employees of Quantum Resources Management, compensation will be paid by Quantum Resources Management and reimbursed by us. In addition to compensation received from Quantum Resources Management related to other service, Mr. Smith and Mr. Campbell will each receive from Quantum Resources Management an addition to his annual salary and Mr. Burgher will receive an annual salary, each in respect of his service as our executive officers; these salaries are included in the administrative services fee that we will pay our general partner, and will not result in any additional payments from us to our general partner (or from our general partner to Quantum Resources Management) in excess of the 3.5% of Adjusted EBITDA, prior to December 31, 2012. After December 31, 2012, we will be obligated to reimburse our general partner for all payments it makes to Quantum Resources Management under the services agreement, which will include the full amount of the annual salary of Mr. Burgher and the portion of the annual salaries of Mr. Smith and Mr. Campbell allocable to their service as executive officers of our general partner. Additionally, both owners of our general partner have agreed to pay Mr. Burgher up to 0.75% of each owner’s share of any management incentive fee paid to our general partner during the period of his employment. The portion of any quarterly management incentive fee paid to Mr. Burgher will not be an expense reimbursed by our general partner or us under the services agreement.

The executive officers of our general partner, as well as the employees of Quantum Resources Management who provide services to us, may participate in employee benefit plans and arrangements sponsored by Quantum Resources Management, including plans that may be established in the future.

Upon the consummation of this offering, the board of directors of our general partner has agreed to award restricted units with a nominal value of $1,500,000 to Mr. Burgher. The restricted units will be awarded under the long-term incentive plan described below, will vest ratably over five years from October 1, 2010, and will be entitled to receive quarterly distributions during the vesting period. We anticipate that, following the closing of this offering, the board of directors of our general partner will grant awards to our other key employees and our outside directors pursuant to the long-term incentive plan; however, the board has not made any determination as to the number of awards, the type of awards or when the awards would be granted. We anticipate that the vesting of our equity awards to executive officers of our general partner will be tied to time and performance thresholds. We expect that annual bonuses will be determined based on a combination of our partnership’s performance and the individual’s impact on our partnership’s performance.

Compensation Committee Interlocks and Insider Participation

As a limited partnership, we are not required by the NYSE to establish a compensation committee. Although the board of directors of our general partner does not currently intend to establish a compensation committee, it may do so in the future.

Compensation Discussion and Analysis

General

All of our executive officers and other employees necessary to operate our business will be employed and compensated by Quantum Resources Management, subject to reimbursement by us to the extent provided for in the services agreement. We and our general partner were formed in September 2010; therefore, we incurred no cost or liability with respect to compensation of our executive officers, nor has our general partner accrued any liabilities for management incentive or retirement benefits for our executive officers for the fiscal year ended December 31, 2009 or for any prior periods.

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Our general partner’s executive officers will manage and operate our business as part of the services provided by Quantum Resources Management to our general partner under the services agreement, and the compensation for all of our executive officers will be indirectly paid by us to the extent provided for in the services agreement, except that the portion of any quarterly management incentive fee paid to Mr. Burgher will not be an expense reimbursed by our general partner or us. We will reimburse our general partner for payments to Quantum Resources Management. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Services Agreement”on page 188 of this prospectus and “ — Reimbursement of Expenses of Our General Partner” on page 175 of this prospectus.

Our general partner’s board of directors will have responsibility and authority for compensation related decisions for the executive officers of our general partner in respect of their service to us. Quantum Resources Management, however, will have responsibility and authority for compensation related decisions for the executive officers of our general partner in respect of their service to the Fund or other entities. When he ceases serving as Interim Chief Financial Officer of the Fund, Mr. Burgher will be the only executive officer of our general partner who provides services solely to us. As a result, he will be the only current executive officer of our general partner for whom the board of directors of our general partner has sole responsibility and authority for compensation related decisions. In making compensation related decisions in respect of our executive officers’ service to us, the board of directors of our general partner, or a committee thereof, will take into account the amounts of such executive officers’ compensation paid by Quantum Resources Management, if any, allocated to our general partner. The board of directors of our general partner, or a committee thereof, also has responsibility and authority to make awards to all executive and non-executive officers of our general partner under the long-term incentive plan, which is described below.

Because it is a private company, Quantum Resources Management has not historically had any formal compensation policies or practices. Rather, all compensation decisions, including those for the executive officers of our general partner, have been made at the discretion of the individuals who control Quantum Resources Management, including Donald D. Wolf, Toby R. Neugebauer and S. Wil VanLoh, Jr., each of whom are directors of our general partner. Other than the incremental salaries paid to Messers. Smith and Campbell in respect of service to us and Mr. Burgher’s compensation, however, Quantum Resources Management does not anticipate paying any additional compensation to the executive officers of our general partner in respect of service to us. Rather, the board of directors of our general partner, or a committee thereof, will have responsibility and authority for any additional compensation paid to the executive officers of our general partner in respect of their service to us.

We expect that the future compensation of our executive and non-executive officers will include a significant component of incentive compensation based on our performance. We expect to employ a compensation philosophy that will emphasize pay-for-performance (primarily the ability to increase sustainable quarterly distributions to unitholders), which will be based on a combination of our partnership’s performance and the individual’s impact on our partnership’s performance and will place the majority of each officer’s compensation at risk. The performance metrics governing incentive compensation will not be tied in any way to the performance of entities other than our partnership—specifically, such performance metrics will not be tied in any way to the performance of as Quantum Resources Management, the Fund, Quantum Energy Partners, or any other affiliate of ours. We believe this pay-for-performance approach generally aligns the interests of our executive officers with that of our unitholders, and at the same time enables us to maintain a lower level of base overhead in the event our operating and financial performance fails to meet expectations. We will design our executive compensation to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our unitholders, and to reward success in reaching such goals.

We expect that we will use three primary elements of compensation to fulfill that design — salary, cash bonus and long-term equity incentive awards. Cash bonuses and equity incentives (as opposed to

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salary) represent the performance driven elements. They are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals’ cash bonuses reflects their relative contribution to achieving or exceeding annual goals, and the determination of specific individuals’ long-term incentive awards is based on their expected contribution in respect of longer term performance objectives.

Quantum Resources Management does not maintain a defined benefit or pension plan for its executive officers, because it believes such plans primarily reward longevity rather than performance. Quantum Resources Management provides a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance. Employees provided to us under the services agreement will be entitled to the same basic benefits.

Awards Under Our Long-Term Incentive Plan

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as a director of our general partner. Our general partner anticipates that each director who is not an officer or employee of our general partner or its affiliates will receive compensation for attending meetings of the board of directors, as well as committee meetings. Our general partner has agreed to pay Mr. Wolf $200,000 in annual compensation for his service as a director of our general partner. Additionally, both owners of our general partner have agreed to pay Mr. Wolf up to 0.75% of each owner’s share of any management incentive fee paid to our general partner during the period of his service as a director our general partner. We will reimburse our general partner for the full amount of Mr. Wolf’s $200,000 in annual compensation for board services, in addition to reimbursing our general partner for payments to Quantum Resources Management under the services agreement. The portion of any quarterly management incentive fee paid to Mr. Wolf will not be an expense reimbursed by our general partner or us under the services agreement. The amount of compensation to be paid to other non-employee directors has not yet been determined.

In addition, each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

Long-Term Incentive Plan

Our general partner intends to adopt the QRE GP, LLC Long-Term Incentive Plan for employees, officers, consultants and directors of our general partner and those of its affiliates, including Quantum Resource Management, who perform services for us. The long-term incentive plan will consist of the following components: unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The long-term incentive plan will initially limit the number of units that may be delivered pursuant to vested awards to 1,800,000 common units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan will be administered by the board of directors of our general partner or a committee thereof, which we refer to as the plan administrator. The plan administrator may also delegate its duties as appropriate. We currently expect that the conflicts committee will be the committee designated as the plan administrator.

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The plan administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire on the earliest of (i) the date on which all common units available under the plan for grants have been paid to participants, (ii) termination of the plan by the plan administrator or (iii) the date 10 years following its date of adoption.

Restricted Units

A restricted unit is a common unit that vests over a period of time, and during that time, is subject to forfeiture. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.

Phantom Units

A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives.

Unit Options

The long-term incentive plan will permit the grant of options covering common units. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options will typically have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.

Unit Appreciation Rights

The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit appreciation rights will typically have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.

Distribution Equivalent Rights

The plan administrator may, in its discretion, grant distribution equivalent rights, or DERs, in tandem with phantom unit awards or other award under the long-term incentive plan. DERs entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.

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Other Unit-Based Awards

The long-term incentive plan will permit the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash or a combination thereof, as provided in the grant agreement.

Unit Awards

The long-term incentive plan will permit the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.

Change in Control; Termination of Service

Awards under the long-term incentive plan will vest and/or become exercisable, as applicable, upon a “change in control” of us or our general partner, unless provided otherwise by the plan administrator. The consequences of the termination of a grantee’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

Source of Units

Common units to be delivered pursuant to awards under the long-term incentive plan may be common units acquired by our general partner in the open market, from any other person, directly from us or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term incentive plan, the total number of common units outstanding will increase.

Relation of Compensation Policies and Practices to Risk Management

We anticipate that our compensation policies and practices will reflect the same philosophy and approach as Quantum Resources Management’s. Accordingly, such policies and practices will be designed to provide rewards for short-term and long-term performance, both on an individual basis and at the entity level. In general, optimal financial and operational performance, particularly in a competitive business, requires some degree of risk-taking. Accordingly, the use of compensation as an incentive for performance can foster the potential for management and others to take unnecessary or excessive risks to reach performance thresholds which qualify them for additional compensation.

From a risk management perspective, our policy will be to conduct our commercial activities within pre-defined risk parameters that are closely monitored and are structured in a manner intended to control and minimize the potential for unwarranted risk-taking. We also routinely monitor and measure the execution and performance of our projects and acquisitions relative to expectations.

We expect our compensation arrangements to contain a number of design elements that serve to minimize the incentive for taking unwarranted risk to achieve short-term, unsustainable results. Those elements include delaying the rewards and subjecting such rewards to forfeiture for terminations related to violations of our risk management policies and practices or of our code of conduct.

In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

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SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common and subordinated units that, upon the consummation of this offering and the related transactions and assuming the underwriters do not exercise their option to purchase additional common units, will be owned by:


	•	each person who then will beneficially own more than 5% of the then outstanding common units;

	•	each director and director nominee of our general partner;

	•	each named executive officer of our general partner; and

	•	all directors, director nominees and executive officers of our general partner as a group.


											Percentage
											of Total
			Percentage of					Percentage of			Common and
	Common		Common			Subordinated		Subordinated			Subordinated
	Units to be		Units to be			Units to be		Units to			Units to
	Beneficially		Beneficially			Beneficially		be Beneficially			be Beneficially
Name of Beneficial Owner(1)	Owned(2)		Owned(3)			Owned		Owned			Owned(3)

The Fund(4)		13,547,737		47.5	%		7,145,866		100.0	%		57.9	%
Donald D. Wolf(4)		—		—			—		—			—
Alan L. Smith(4)(5)		13,547,737		47.5	%		7,145,866		100.0	%		57.9	%
John H. Campbell(4)(5)		13,547,737		47.5	%		7,145,866		100.0	%		57.9	%
Cedric W. Burgher(3)		—		—			—		—			—
Gregory S. Roden		—		—			—		—			—
Howard K. Selzer		—		—			—		—			—
Toby R. Neugebauer(4)(5)		13,547,737		47.5	%		7,145,866		100.0	%		57.9	%
S. Wil VanLoh, Jr.(4)(5)		13,547,737		47.5	%		7,145,866		100.0	%		57.9	%
Donald E. Powell		—		—			—		—			—
All named executive officers, directors and director nominees as a group (9 persons)		13,547,737		47.5	%		7,145,866		100.0	%		57.9	%


(1)		The address for all beneficial owners in this table is 5 Houston Center, 1401 McKinney Street, Suite 2400, Houston, Texas 77010.

(2)		Does not include any common units that may be purchased in the directed unit program. Please read “Underwriting” on page 244.

(3)		Does not include any restricted units to be issued to Mr. Burgher upon the consummation of this offering.

(4)		QA Global GP, LLC (“HoldCo GP”) may be deemed to beneficially own the interests in us held by Quantum Resources A1, LP (“QRA”), Quantum Resources B, LP (“QRB”), Quantum Resources C, LP (“QRC”), QAB Carried WI, LP (“QAB”), QAC Carried WI, LP (“QAC”) and Black Diamond Resources, LLC (“Black Diamond”). HoldCo GP is the sole general partner of QA Holdings, LP, which is the sole owner of QA GP, LLC, which is the sole general partner of The Quantum Aspect Partnership, LP, which is the sole general partner of each of QRA, QRB and QRC. QAB, QAC and Black Diamond are wholly owned by QA Holdings, LP. QRA, QRB, QRC, QAB, QAC and Black Diamond hold the following limited partner interests in us:


	•	QRA owns 12,386,181 common units and 6,533,194 subordinated units;

	•	QRB owns 223,382 common units and 117,825 subordinated units;

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	•	QRC owns 396,524 common units and 209,150 subordinated units;

	•	QAB owns 4,559 common units and 2,405 subordinated units;

	•	QAC owns 8,092 common units and 4,268 subordinated units; and

	•	Black Diamond owns 528,998 common units and 279,025 subordinated units.


		The Fund’s common units will be reduced to the extent the underwriters exercise their option to purchase additional common units. Please read “Prospectus Summary — The Offering” on page 15 for a description of the underwriters’ option to purchase additional common units.

		Three directors of our general partner, Messrs. Wolf, Neugebauer and VanLoh, and two directors and executive officers of our general partner, Messrs. Smith and Campbell, are also members of the board of directors of HoldCo GP, and as such, are entitled to vote on decisions to vote, or to direct to vote, and to dispose, or to direct the disposition of, the common units and subordinated units held by the Fund but cannot individually or together control the outcome of such decisions. HoldCo GP and Messrs. Wolf, Neugebauer, VanLoh, Smith and Campbell disclaim beneficial ownership of the common units and subordinated units held by the Fund.

(5)		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. As indirect owners of our general partner, Messrs. Neugebauer, VanLoh, Smith and Campbell will share in distributions made by us with respect to units held by our general partner in proportion to their respective ownership interests. Messrs. Neugebauer, VanLoh, Smith and Campbell, by virtue of their ownership interest in our general partner, may be deemed to beneficially own the units held by our general partner.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Upon the 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. In addition, our general partner will own a 0.1% general partner interest in us, evidenced by 35,729 general partner units. These percentages do not reflect any common units that may be issued under the long-term incentive plan that our general partner expects to adopt prior to the closing of this offering.

Distributions and Payments to Our General Partner and Its Affiliates

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

Formation Stage


The consideration received by our general partner, the Fund and their respective affiliates prior to or in connection with this offering		• 13,547,737 common units;

		• 7,145,866 subordinated units;

		• 35,729 general partner units;

		• the right to receive the management incentive fee; and

		• approximately $300.0 million in cash.

		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 first bullet above) will decrease 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.

Operational Stage


Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions to our unitholders and general partner pro rata, including our general partner and its affiliates, as the holders of 13,547,737 common units, all of the subordinated units and 35,729 general partner units.

		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.06 million on their general partner units, $22.4 million on their common units and $11.8 million on their subordinated units.

		For more information regarding distributions on our general partner’s units, please read “— Limited Liability Company Agreement of Our General Partner — Distributions on Our General Partner’s Units” on page 187.

Management incentive fee		Under our partnership agreement, for each quarter for which we have paid distributions that equaled or exceeded the Target

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		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.

		This 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 third-party 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.

		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.

		For more information regarding the allocation under the limited liability agreement of our general partner of our management incentive fee and distributions paid with respect to Class B

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		units issued upon conversion of the management incentive fee, please read “— Limited Liability Company Agreement of Our General Partner — Allocation of the Management Incentive Fee and — Allocation of Distributions Paid with Respect to Class B Units Issued Upon Conversion of the Management Incentive Fee” beginning on page 187.

Conversion of the management incentive fee into Class B units and 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 holder. If our general partner exercises its right to convert a portion 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 subsequent quarters, subject to potential increase 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.

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		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” beginning on page 101.

Payments to our general partner and its affiliates		Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. 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. For the nine months ended September 30, 2010, 3.5% of our unaudited pro forma Adjusted EBITDA, calculated prior to 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. Please read ‘‘— Services Agreement” below.

Withdrawal or removal of our general partner		In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest in us and right to the management incentive fee for a cash payment equal to the fair market value of that interest and right. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner in us and right to the management incentive fee for their fair market value or to convert that interest and right into common units.

*Liquidation Stage*

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

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Limited Liability Company Agreement of our General Partner

Distributions on Our General Partner Units. Our general partner is 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. As indirect owners of our general partner, Messrs. Neugebauer, VanLoh, Smith and Campbell will share, in proportion to their respective ownership interests in our general partner, in distributions made by us with respect to the 35,729 general partner units held by our general partner.

Allocation of the Management Incentive Fee. Our general partner will allocate to its members any management incentive fee paid to our general partner in the following manner:


	•	Fund Management Incentive Fee. With respect to any management incentive fee paid to our general partner that is attributable to oil and natural gas properties and other assets owned or subsequently acquired by the Fund following the closing of this offering and sold to us:


	•	Prior to the termination of the investment period, as such term is defined in the limited liability company agreement of our general partner, and which termination will occur no later than June 30, 2011, the entity controlled by Mr. Neugebauer and Mr. VanLoh will receive 72% of such portion of the management incentive fee, and the entity controlled by Mr. Smith and Mr. Campbell will receive 28% of such portion of the management incentive fee;

	•	From and after the termination of the investment period but prior to July 1, 2013, the entity controlled by Mr. Neugebauer and Mr. VanLoh will receive 68.4% of such portion of the management incentive fee, and the entity controlled by Mr. Smith and Mr. Campbell will receive 31.6% of such portion of the management incentive fee; and

	•	After June 30, 2013, the entity controlled by Mr. Neugebauer and Mr. VanLoh will receive 64.8% of such portion of the management incentive fee, and the entity controlled by Mr. Smith and Mr. Campbell will receive 35.2% of such portion of the management incentive fee.


	•	Non-Fund Management Incentive Fee. With respect to any management incentive fee paid to our general partner that is attributable to oil and natural gas properties and other assets acquired by us from third parties other than the Fund following the closing of this offering, the entity controlled by Mr. Neugebauer and Mr. VanLoh will receive 50% of such portion of the management incentive fee, and the entity controlled by Mr. Smith and Mr. Campbell will receive 50% of such portion of the management incentive fee.

Additionally, both owners of our general partner have agreed to pay Mr. Burgher and Mr. Wolf each 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.

Allocation of Distributions Paid with Respect to Class B Units Issued Upon Conversion of the Management Incentive Fee. Assuming all members of our general partner elect to convert into Class B units their respective proportionate share of the management incentive fee, then any cash distributions on converted Class B units (or any cash proceeds from the sale of Class B units) will be allocated to such members of our general partner based on the source of the assets from which such converted management incentive fee originated as set forth above. Additionally, each of Mr. Burgher and Mr. Wolf will be entitled to receive his proportionate share of any Class B units into which his share of the management incentive fee is converted.

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Agreements Governing the Transactions

In connection with the closing of this offering, we, our general partner and its affiliates will enter into the various documents and agreements that will effect the transactions described in “Prospectus Summary — Formation Transactions and Partnership Structure” on page 8 including the vesting of assets in, and the assumption of liabilities by, us and the application of the proceeds of this offering. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets to us, will be paid from the proceeds of this offering.

Services Agreement

Contemporaneously with the closing of this offering, our general partner will enter into a services agreement with Quantum Resources Management. 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. 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, which is inclusive of the incremental costs of becoming a publicly-traded limited partnership. 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. 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 by Quantum Resources Management to its affiliates. 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. Quantum Resources Management has not yet determined the method by which it will allocate expenses incurred on our behalf; however, we expect that Quantum Resources Management will determine the method by which it will allocate expenses incurred on our behalf by June 30, 2012, and we will inform our unitholders of the allocation method by means of a Current Report on Form 8-K following such determination. Quantum Resources Management will not be liable to us for its performance of, or failure to perform, services under the services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with affiliates of our general partner, including the Fund, that will address competition and indemnification matters, as well as our right to participate in certain transactions with the Fund. Any or all of the provisions of the omnibus agreement, other than the indemnification provisions described below, will terminate upon a change of control of us or our general partner.

Competition. None of the affiliates of the Fund will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. The Fund will be permitted to compete with us and may acquire 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 those assets, except as provided in the right of first offer and the participation right under the omnibus agreement.

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Indemnification. Pursuant to the omnibus agreement, the Fund will indemnify us against (i) title defects, subject to a $75,000 per claim de minimus exception, for amounts in excess of a $4.0 million threshold, and (ii) income taxes attributable to pre-closing operations as of the closing date of this offering. The Fund’s indemnification obligation will (i) survive for one year after the closing of this offering with respect to title, and (ii) terminate upon the expiration of the applicable statute of limitations with respect to income taxes. We will indemnify the Fund against certain potential environmental claims, losses and expenses associated with the operation of our business that arise after the consummation of this offering.

Right of First Offer and Participation Right. Under the terms of the 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 allow us to participate in 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 participate in at least 25% of each acquisition opportunity available to it, so long as at least 70% of the allocated value 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 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 after the date the omnibus agreement is executed.

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Contracts with Affiliates

Amended and Restated Limited Liability Company Agreement of QRE GP, LLC

The owners of our general partner expect to amend and restate its Limited Liability Company Agreement prior to the closing of this offering. Among other provisions, the Amended and Restated Limited Liability Company Agreement of QRE GP, LLC will allocate the management incentive fee amongst its owners in proportion to their ownership interests or by an alternative arrangement.

Stakeholders’ Agreement

Prior to filing our registration statement relating to this offering, we, the Fund and our general partner entered into an agreement relating to:


	•	the contribution of the Partnership Properties to us in exchange for cash, common units and subordinated units;

	•	the issuance of the general partner units to our general partner, and providing for our general partner’s management incentive fee payable by us and the conversion of such fee into Class B units; and

	•	registration rights for the benefit of the Fund and our general partner.

We refer to this agreement as our “Stakeholders’ Agreement” and have filed it as an exhibit to the registration statement of which this prospectus is a part. The distributions and payments to be made by us to our general partner and its affiliates in connection with our formation and ongoing operation were determined by and among affiliated entities and, consequently, were not the result of arms-length negotiations.

Allocation of Residual Units. Pursuant to the terms of the Stakeholders’ Agreement, at the closing of this offering, each fund and other entity comprising the Fund contributing the Partnership Properties to us will be allocated common units and subordinated units pursuant to a formula based on each fund’s ownership percentage in such Partnership Properties. Specifically, the Stakeholders’ Agreement provides that upon the closing of this offering, the “residual units” of our partnership will be determined by subtracting the number of common units issued by us to the public unitholders (plus general partner units issued to our general partner) from the total number of units outstanding following the closing. The residual units will consist of the following: (a) subordinated units equal to twenty percent (20%) multiplied by the total outstanding units prior to closing and issuance of general partner units and (b) common units equal to the number of residual units minus the number of subordinated units. Each of the contributors of Partnership Properties will receive:


	•	a number of residual common units equal to the aggregate number of residual common units multiplied by such contributor’s ownership percentage in the Partnership Properties, less fifteen percent (15%) to cover the underwriters’ option to purchase additional common units from us; and

	•	a number of residual subordinated units equal to the aggregate number of residual subordinated units multiplied by such contributor’s ownership percentage in the Partnership Properties.

If the underwriters do not exercise their option to purchase additional common units prior to the expiration of the option period, we will issue the balance of the residual common units to the Fund in accordance with each contributor’s ownership percentage in the Partnership Properties. To the extent the underwriters exercise their option to purchase additional common units before the expiration of the option period, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the public, and the remainder of the residual common units subject to the option, if any, will be issued to the Fund at the expiration of the option period in accordance with each contributor’s ownership percentage in the Partnership Properties. The proceeds, after deducting the underwriters’ discounts, from any exercise of the underwriters’ option to purchase additional common units will be paid to the Fund in accordance with each contributor’s percentage interest in the Partnership Properties.

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Distribution of Cash. Pursuant to the terms of the Stakeholders’ Agreement, at the closing of this offering, each fund comprising the Fund will receive a cash distribution based on such fund’s respective ownership percentage in the Partnership Properties to be contributed to us at the closing. This cash distribution to the Fund will be approximately $300 million, comprised of approximately $275.0 million of net proceeds from this offering, after deducting estimated underwriters’ discounts, structuring fees and offering expenses, and $25 million of our $225 million of borrowings under our new credit facility. We will assume approximately $200 million of the Fund’s debt that currently burdens the Partnership Properties at the closing of this offering as described in “Prospectus Summary — Formation Transactions and Partnership Structure” on page 8. We will use $200 million of the borrowings under our credit facility to repay such assumed debt in full at the closing of this offering.

General Partner Interests. Pursuant to the terms of the Stakeholders’ Agreement, at the closing of this offering, our general partner will receive a number of general partner units equal to 0.1% of the total number of common, subordinated and general partner units to be outstanding following the closing, including the issuance of additional common units upon the exercise or expiration of the underwriters’ option to purchase additional common units. Additionally, our partnership agreement will set forth the terms and conditions of our general partner’s management incentive fee, including our general partner’s ability to convert its management incentive fee into Class B units under certain circumstances. For a description of our general partner’s 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” beginning on page 101.

The following table sets forth the consideration to be received by each fund comprising the Fund as consideration in respect of such fund’s respective percentage interest in the Partnership Properties to be contributed to us at the closing of this offering.


					Aggregate Value of
					Common and
The Fund	Common Units(1)		Subordinated Units		Subordinated Units

Quantum Resources A1, LP		12,386,181		6,533,194	$	378,387,497
Quantum Resources B, LP		223,382		117,825	$	6,824,129
Quantum Resources C, LP		396,524		209,150	$	12,113,489
QAB Carried WI, LP		4,559		2,405	$	139,268
QAC Carried WI, LP		8,092		4,268	$	247,214
Black Diamond Resources, LLC		528,998		279,025	$	16,160,462


(1)		Assumes that the underwriters do not exercise their option to purchase additional common units.

Registration Rights. Pursuant to the Stakeholders’ Agreement, the Fund has the right to require the registration of the units acquired by it upon consummation of this offering, including any common units issued to the Fund upon expiration of the underwriters’ option to purchase additional common units. Subject to the terms of the Stakeholders’ Agreement, the Fund is entitled to make three such demands for registration. Additionally, the Fund and permitted transferees may include any of their units in a registration by us of other units, including units offered by us or any unitholder, subject to customary exceptions. Please read “Certain Relationship and Related Party Transactions — Agreements Governing the Transaction” on page 188.

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Review, Approval or Ratification of Transactions with Related Persons

We expect that we will adopt a Code of Business Conduct and Ethics that will set forth our policies for the review, approval and ratification of transactions with related persons. Upon our adoption of a Code of Business Conduct and Ethics, a director would be expected to bring to the attention of the Chief Executive Officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with the Fund’s and our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner’s board of directors, or the conflicts committee of our general partner’s board of directors.

Upon our adoption of a Code of Business Conduct and Ethics, any executive officer of our general partner will be required to avoid conflicts of interest unless approved by the board of directors.

The board of directors of our general partner will have a standing conflicts committee comprised of at least one independent director and will determine whether to seek the approval of the conflicts committee in connection with future acquisitions of oil and natural gas properties from the Fund or its affiliates. In addition to acquisitions from the Fund or its affiliates, the board of directors of our general partner will also determine whether to seek conflicts committee approval to the extent we act jointly to acquire additional oil and natural gas properties with the Fund. In the case of any sale of equity or debt by us to an owner or affiliate of an owner of our general partner, we anticipate that our practice will be to obtain the approval of the conflicts committee of the board of directors of our general partner for the transaction. 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 has sought the conflicts committee’s approval.

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

We expect that the Fund will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed purchase price of any assets it may offer to us in future periods. In addition to these factors, given that the Fund will be our largest unitholder following the consummation of this offering, the Fund may consider the potential positive impact on its underlying investment in us by offering properties to us at attractive purchase prices. Likewise, the Fund may consider the potential negative impact on its underlying investment in us if we are unable to acquire additional assets on favorable terms, including the negotiated purchase price.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including the Fund, Quantum Resources Management and Quantum Energy Partners) on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. In addition, many of the directors and officers of our general partner serve in similar capacities with Quantum Resources Management and Quantum Energy Partners and their respective affiliates, 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, which may lead to additional conflicts of interest. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

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

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


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

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

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

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

As required by our partnership agreement, the board of directors of our general partner will maintain a conflicts committee comprised of at least one independent director. Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with our general partner or affiliates. If our general partner seeks approval from the conflicts committee, the conflicts committee will determine if the resolution of a conflict of interest with our general partner or its affiliates is fair and reasonable to us. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he or she is acting in our best interest.

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

Other Than Certain Obligations of the Fund and Its General Partner Contained in the 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.

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 obligations of the Fund described below with respect to our omnibus agreement, the Fund and Quantum Energy Partners and their respective affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. 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 reasonably determined 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 comprised of at least 70% proved developed producing reserves. 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.

Neither Our Partnership Agreement Nor Any Other Agreement Requires the Fund or Quantum Energy Partners to Pursue a Business Strategy That Favors Us or Uses Our Assets or Dictates What Markets to Pursue or Grow. Each of the Officers and Directors of the Fund and Quantum Energy Partners Has a Fiduciary Duty to Make These Decisions in the Best Interests of Its Respective Owners, Which May Be Contrary to Our Interests.

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

Our General Partner Is Allowed to Take into Account the Interests of Parties Other Than Us in Resolving Conflicts of Interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include its determination whether or not to consent to any merger or consolidation involving us and its decision to convert its management incentive fee into Class B units.

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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 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. 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 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, please read “Business and Properties — Our Principal Business Relationships” beginning on page 146.

We Do Not Have Any Employees and Rely Solely on the Employees of Quantum Resources Management. Quantum Resources Management Will Also Be Providing Substantially Similar Services to the Fund, and Thus Will Not Be Solely Focused on Managing 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 will agree 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. Additionally, should Quantum Energy Partners form other funds, Quantum Resources Management may also 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

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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 and 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.

Our Partnership Agreement Limits Our General Partner’s Fiduciary Duties to Holders of Our Units and Restricts the Remedies Available to Unitholders for Actions Taken By Our General Partner That Might Otherwise Constitute Breaches of Fiduciary Duty.

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Our partnership agreement contains provisions that reduce the 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, which allows our general partner to consider only the interests and factors that it desires, without a duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

	•	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 and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons, as the case may be, 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 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.

If you purchase any common units, you will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.

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Except in Limited Circumstances, Our General Partner Has the Power and Authority to Conduct Our Business Without Unitholder Approval.

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


	•	the making of any expenditures, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

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

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

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

	•	the distribution of our cash;

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

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

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

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

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

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

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

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “The Partnership Agreement — Limited Voting Rights” on page 207 for information regarding matters that require unitholder approval.

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Our General Partner Determines the Amount and Timing of Asset Purchases and Sales, Capital Expenditures, Borrowings, Issuance of Additional Partnership Interests and the Creation, Reduction or Increase of Reserves, Each of Which Can Affect the Amount of Cash That Is Distributed to Our Unitholders.

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


	•	the manner in which our business is operated;

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

	•	the amount, nature and timing of our capital expenditures;

	•	the amount of borrowings;

	•	the issuance of additional units; and

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

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

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

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

Our General Partner Determines Which Costs Incurred By It Are Reimbursable By Us.

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

Our Partnership Agreement Does Not Restrict Our General Partner from Causing Us to Pay It or Its Affiliates for Any Services Rendered to Us or Entering into Additional Contractual Arrangements with Any of These Entities on Our Behalf.

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

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

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into

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specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

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 such management incentive fee for the fourth quarter in lieu of receiving a cash payment for such 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, a conversion of the management incentive fee may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner. 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.

Certain of Our Executive Officers and Directors Will Be Entitled to Receive Their Respective Shares of Distributions Paid to Our General Partner and the Management Incentive Fee

Allocation of the Management Incentive Fee. Our general partner will allocate to its members any management incentive fee paid to our general partner in the following manner:


	•	Fund Management Incentive Fee. With respect to any management incentive fee paid to our general partner that is attributable to oil and natural gas properties and other assets owned or subsequently acquired by the Fund following the closing of this offering and sold to us:


	•	Prior to the termination of the investment period, as such term is defined in the limited liability company agreement of our general partner, and which termination will occur no later than June 30, 2011, the entity controlled by Mr. Neugebauer and Mr. VanLoh will receive 72% of such portion of the management incentive fee, and the entity controlled by Mr. Smith and Mr. Campbell will receive 28% of such portion of the management incentive fee;

	•	From and after the termination of the investment period but prior to July 1, 2013, the entity controlled by Mr. Neugebauer and Mr. VanLoh will receive 68.4% of such portion of the

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		management incentive fee, and the entity controlled by Mr. Smith and Mr. Campbell will receive 31.6% of such portion of the management incentive fee; and


	•	After June 30, 2013, the entity controlled by Mr. Neugebauer and Mr. VanLoh will receive 64.8% of such portion of the management incentive fee, and the entity controlled by Mr. Smith and Mr. Campbell will receive 35.2% of such portion of the management incentive fee.


	•	Non-Fund Management Incentive Fee. With respect to any management incentive fee paid to our general partner that is attributable to oil and natural gas properties and other assets acquired by us from third parties other than the Fund following the closing of this offering, the entity controlled by Mr. Neugebauer and Mr. VanLoh will receive 50% of such portion of the management incentive fee, and the entity controlled by Mr. Smith and Mr. Campbell will receive 50% of such portion of the management incentive fee.

Our General Partner May Exercise Its Right to Call and Purchase Common Units If It and Its Affiliates Own More Than 80% of the Common Units.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right” on page 216.

Common Unitholders Will Have No Right to Enforce Obligations of Our General Partner and Its Affiliates Under Agreements with Us.

Any agreements between us, on the one hand, and our general partner, the Fund, Quantum Resources Management, Quantum Energy Partners and their respective affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner, the Fund, Quantum Resources Management, Quantum Energy Partners and their respective affiliates in our favor.

Our General Partner and the Fund May Be Able to Amend Our Partnership Agreement without the Approval of Any Other Unitholder After the Subordination Period.

Our general partner has the discretion to propose amendments to our partnership agreement, certain of which may be made by our general partner without unitholder approval. Our partnership agreement generally may not be otherwise amended during the subordination period without the approval of a majority of our public common unitholders. However, after the subordination period has ended, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by the Fund and its affiliates). Upon the consummation of this offering, affiliates of the Fund and Quantum

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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. Assuming that the Fund retains a sufficient number of its common units and that we do not issue additional common units, our general partner and the Fund will have the ability to amend our partnership agreement without the approval of any other unitholder after the subordination period. Please read ‘The Partnership Agreement — Amendment of the Partnership Agreement‘ on page 210.

Our General Partner Intends to Limit Its Liability Regarding Our Obligations.

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

Contracts Between Us, on the One Hand, and Our General Partner and Its Affiliates, on the Other, Will Not Be the Result of Arm’s-Length Negotiations.

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

Our General Partner Decides Whether to Retain Separate Counsel, Accountants or Others to Perform Services for Us.

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. The attorneys, independent accountants and others who perform services for us are selected by our general partner, or the conflicts committee of our general partner’s board of directors, and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Fiduciary Duties

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

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner, the Fund, Quantum Resources Management, Quantum Energy Partners and their respective affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors has fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to our unitholders. Without these modifications, our general partner’s

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ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration the interests of all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest.

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


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

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

Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or

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		omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with the knowledge that such conduct was unlawful.

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

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

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

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

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

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification” on page 218.

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units, Class B units, if any, and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 70. For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement” beginning on page 206.

Transfer Agent and Registrar

Duties

Computershare Trust Company, N.A. will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by our unitholders:


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

	•	special charges for services requested by a common unitholder; and

	•	other similar fees or charges.

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

Resignation or Removal

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

Transfer of Common Units

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


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

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

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

Our general partner may request that a transferee of common units certify that such transferee is an Eligible Holder. As of the date of this prospectus, an Eligible Holder means:


	•	a citizen of the United States;

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	•	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.

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

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

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

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

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included as Appendix A in this prospectus. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

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


	•	with regard to distributions of available cash, please read “Our Cash Distribution Policy and Restrictions on Distributions” beginning on page 70 and “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee” beginning on page 93;

	•	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties” beginning on page 193;

	•	with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units” on page 204; and

	•	with regard to allocations of taxable income, taxable loss and other matters, please read “Material Tax Consequences” beginning on page 222.

Organization and Duration

Our partnership was organized on September 20, 2010 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

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

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

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership interests as well as to our general partner in respect of its general partner interest. For a description of these cash distribution provisions and the management incentive fee, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee” beginning on page 93.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described under “— Limited Liability” on page 209. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest in us if we issue additional units. Our general partner’s 0.1% interest in us, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future (other than

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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 Class B units in connection with a conversion of the management incentive fee, 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 to maintain its 0.1% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash, and our general partner may fund its capital contribution by the contribution to us of common units or other property.

Limited Voting Rights

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

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


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

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

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

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


Issuance of additional units		No approval right. Please read “— Issuance of Additional Interests” on page 210.

Amendment of the partnership agreement		Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement” on page 210.

Merger of our partnership or the sale of all or substantially all of our assets		Unit majority, in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets” on page 212.

Dissolution of our partnership		Unit majority. Please read “— Dissolution” on page 213.

Continuation of our business upon dissolution		Unit majority. Please read “— Dissolution” on page 213.

Withdrawal of our general partner		Prior to December 31, 2020, under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of Our General Partner” on page 214.

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Removal of our general partner		Not less than 662/3% of the outstanding units, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner” on page 214.

Transfer of our general partner interest		Our general partner may transfer without a vote of our unitholders all, but not less than all, of its general partner interest in us to an affiliate or another person (other than an individual) in connection with its merger or consolidation with or into, or sale of all, or substantially all, of its assets to, such person. The approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third-party prior to December 31, 2020. Please read “— Transfer of General Partner Units” on page 215.

Assignment of management incentive fee		Our general partner may assign its rights to receive the management incentive fee at any time without unitholder approval in certain circumstances, so long as it continues to serve as our general partner. Prior to December 31, 2020, any other assignment of the right to receive the management incentive fee will require the affirmative vote of the holders of a majority of our outstanding common units, excluding common units held by our general partner and its affiliates. On or after December 31, 2020, the right to receive the management incentive fee will be freely assignable. Please read “— Assignment of Management Incentive Fee” on page 215.

Transfer of ownership interests in our general partner		No approval required at any time. Please read ‘‘— Transfer of Ownership Interests in Our General Partner” on page 215.

Applicable Law; Forum, Venue and Jurisdiction

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


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

	•	brought in a derivative manner on our behalf;

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

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

	•	asserting a claim governed by the internal affairs doctrine,

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

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provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

Limited Liability

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


	•	to remove or replace our general partner;

	•	to approve some amendments to the partnership agreement; or

	•	to take other action under the partnership agreement

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

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

Our operating subsidiary currently conducts business in Alabama, Arkansas, Florida, Kansas, Louisiana, New Mexico, Oklahoma and Texas, and we may have operating subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as an owner of our operating subsidiary may require compliance with legal requirements in the jurisdictions in which our operating subsidiary conducts business, including qualifying our operating subsidiary to do business there.

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

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personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.

Issuance of Additional Interests

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

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

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

If we issue additional partnership interests (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 Funds upon expiration of the option to purchase additional common units, the issuance of partnership interests in connection with a conversion of the management incentive fee or the issuance of partnership interests upon conversion of outstanding partnership interests) our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 0.1% general partner interest in us. Our general partner’s 0.1% general partner interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the aggregate percentage interest in us of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. To adopt a proposed amendment, other than the amendments discussed below under ‘‘— No Unitholder Approval” on page 211, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:


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

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

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon the consummation of this offering, the Fund will own an aggregate of approximately 47.5% of our outstanding common units and 100% of our subordinated units, representing an aggregate of approximately 57.9% of our outstanding units.

No Unitholder Approval

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


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

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

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

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

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

	•	an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or rights to acquire partnership interests;

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

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

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

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

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

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

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


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

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

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

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

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

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our limited partners or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under Delaware law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected, but no vote will be required by any class or classes or type or types of limited partners that our general partner determines are not adversely affected in any material respect. Any amendment that reduces the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

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

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

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all

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or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction will not result in a material amendment to our partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction, and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

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

Dissolution

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


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

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

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

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

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


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

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

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee —

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Distributions of Cash Upon Liquidation” on page 106. The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2020 without obtaining the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2020, our general partner may withdraw as our general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw as our general partner without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Units” on page 215.

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters is not obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Dissolution” on page 213.

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common and subordinated units, including common units held by our general partner and its affiliates, voting as a single class. The ownership of more than 331/3% of our outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. Upon the consummation of this offering, the Fund will own an aggregate of approximately 47.5% of our outstanding common units and 100% of our subordinated units representing approximately 57.9% of our outstanding units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:


	•	all subordinated units held by any person who did not, and whose affiliates did not, vote any units in favor of the removal of the general partner, will immediately and automatically convert into common units on a one-for-one basis; and

	•	if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest in us and right to the management incentive fee for a cash payment equal to the fair market value of that interest and right. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner in us and right to the management incentive fee for their fair market value. In each case, this fair market value will be

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determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest in us and the right to the management incentive fee will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Except for the transfer by our general partner of all, but not less than all, of its general partner units to:


	•	an affiliate of our general partner (other than an individual); or

	•	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner units to another person prior to December 31, 2020, without the approval of the holders of at least a majority of our outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer common units or subordinated units to one or more persons without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner to an affiliate or a third-party without the approval of our unitholders.

Assignment of Management Incentive Fee

Our general partner or a subsequent holder may assign its rights to receive the management incentive fee and to convert such management incentive fee into Class B units to (i) an affiliate of the holder (other than an individual) or (ii) another entity as part of the merger or consolidation of such holder with or into such entity, the sale of all of the ownership interests in such holder to such entity or the sale of all or substantially all of such holder’s assets to such entity without the prior approval of the unitholders; provided that, in the case of the sale of ownership interests in such holder, the initial holder of the right to receive the management incentive fee continues to serve as our general partner following such sale. Prior to December 31, 2020, any other assignment of the right to receive the management incentive fee will require the affirmative vote of the holders of a majority of our outstanding common

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units, excluding common units held by our general partner and its affiliates. On or after December 31, 2020, the right to receive the management incentive fee will be freely assignable.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change the management of our general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of our then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:


	•	the highest cash price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

	•	the average of the daily closing prices of the limited partner interests of such class over the 20 trading days preceding the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Units” on page 235.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by Non-Eligible Holders will be voted by our general partner and our general partner will cast the votes on those units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

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Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Interests” on page 210. However, if at any time any person or group, other than our general partner and its affiliates or a direct or subsequently approved transferee of our general partner or its affiliates and specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of any common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability” on page 209, the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Eligible Holders; Redemption

We currently own interests in oil and natural gas leases on United States federal lands and may acquire additional interests in the future. To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands, our general partner, acting on our behalf, may request that transferees fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify, that the unitholder is an Eligible Holder. As used in our partnership agreement, 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.

For the avoidance of doubt, 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. This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If, following a request by our general partner, a transferee or unitholder, as the case may be, fails to furnish:


	•	a transfer application containing the required certification;

	•	a re-certification containing the required certification within 30 days after request; or

	•	provides a false certification,

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then, as the case may be, such transfer will be void or we will have the right, which we may assign to any of our affiliates, to acquire all, but not less than all, of the units held by such unitholder. Further, the units held by such unitholder will not be entitled to any voting rights.

The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	•	our general partner;

	•	any departing general partner;

	•	any person who is or was an affiliate of our general partner or any departing general partner;

	•	any person who is or was a director, officer, manager, managing member, fiduciary or trustee of any entity set forth in the preceding three bullet points;

	•	any person who is or was serving as a director, officer, manager, managing member, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

	•	any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance covering liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These 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.

Immediately prior to the closing of this offering, our general partner will enter into a services agreement with Quantum Resources Management, pursuant to which, 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. The services agreement provides

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that employees of Quantum Resources Management (including the persons who are executive officers of our general partner) will devote such portion of their time as may be reasonable and necessary for the operation of our business. It is anticipated that certain of the executive officers of our general partner will devote significantly less than a majority of their time to our business for the foreseeable future.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For financial reporting and tax purposes, our fiscal year end is December 31.

We will furnish or make available to record holders of common units, within 90 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also furnish or make available summary financial information within 45 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on the cooperation of our unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, obtain:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

	•	copies of our partnership agreement, our certificate of limited partnership, related amendments and any powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts. Please read “Units Eligible for Future Sale” on page 220.

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby, the Fund will hold an aggregate of 13,547,737 common units and 7,145,866 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1.0% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A unitholder who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell his common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.

Our partnership agreement does not restrict our ability to issue any partnership interests. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Interests” on page 210.

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units or other partnership interests that they hold, which we refer to as registerable securities. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any registerable securities to require registration of such registerable securities and to include any such registerable securities in a registration by us of common units or other partnership interests, including common units or other partnership interests offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of our general partner. Additionally, pursuant to the Stakeholders’ Agreement, the Fund has the right to require the registration of the units acquired by it upon consummation of this offering. Subject to the terms of the Stakeholders’ Agreement, the Fund is entitled to make three such demands for registration. Additionally, the Fund and permitted transferees may include any of their units in a registration by us of other units, including units offered by us or any unitholder, subject to customary exceptions. In connection with any registration of units held by our general partner or its affiliates, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Except as described below, our general partner and its affiliates may sell their

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material U.S. federal, state and local tax consequences that may be relevant to prospective unitholders and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins insofar as it describes legal conclusions with respect to matters of U.S. federal income tax law. Such statements are based on the accuracy of the representations made by our general partner and us to Vinson & Elkins, and statements of fact do not represent opinions of Vinson & Elkins. To the extent this section discusses U.S. federal income taxes, that discussion is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to QR Energy, LP and our subsidiaries.

This section does not address all U.S. federal, state and local tax matters that affect us or our unitholders. To the extent that this section relates to taxation by a state, local or other jurisdiction within the United States, such discussion is intended to provide only general information. We have not sought the opinion of legal counsel regarding U.S. state, local or other taxation and, thus, any portion of the following discussion relating to such taxes does not represent the opinion of Vinson & Elkins or any other legal counsel. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States, whose functional currency is the U.S. dollar and who hold units as a capital asset (generally, property that is held as an investment). This section has no application to corporations, partnerships (and entities treated as partnerships for U.S. federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts, employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each prospective unitholder to consult such unitholder’s own tax advisor in analyzing the U.S. federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from his ownership or disposition of his units.

No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any matter that affects us or our unitholders. Instead, we will rely on opinions and advice of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our units and the prices at which such units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, our tax treatment, or the tax treatment of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Vinson & Elkins has not rendered an opinion with respect to the following specific U.S. federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales” on page 228); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Units — Allocations Between Transferors and Transferees” on page 236); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “Tax Consequences of Unit Ownership — Section 754 Election” on page 229 and “— Uniformity of Units” on page 237).

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Taxation of QR Energy, LP

Partnership Status

We will be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for U.S. federal income taxes. Instead, each of our unitholders will be required to take into account his respective share of our items of income, gain, loss and deduction in computing his U.S. federal income tax liability as if the unitholder had earned such income directly, even if no cash distributions are made to the unitholder. Distributions by us to a unitholder generally will not be taxable to us or the unitholder unless the amount of cash distributed to the unitholder exceeds the unitholder’s tax basis in his units.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships for which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from exploration and production of certain natural resources, including oil, natural gas, and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 5% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner, and a review of the applicable legal authorities, Vinson & Elkins is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating company for U.S. federal income tax purposes. It is the opinion of Vinson & Elkins that we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for U.S. federal income tax purposes.

In rendering its opinion, Vinson & Elkins has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins has relied include, without limitation:

(a) neither we nor any of our operating subsidiaries has elected or will elect to be treated as a corporation;

(b) for each taxable year, including short taxable years occurring as a result of a constructive termination, more than 90% of our gross income has been and will be income that Vinson & Elkins has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and

(c) each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, natural gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins has opined or will opine result in qualifying income.

We believe that these representations have been true in the past and expect that these representations will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we have transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to our unitholders in liquidation of their interests in

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us. This deemed contribution and liquidation should be tax-free to our unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for U.S. federal income tax purposes.

If we were treated as an association taxable as a corporation for U.S. federal income tax purposes in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return, rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital to the extent of the unitholder’s tax basis in our units, or taxable capital gain, after the unitholder’s tax basis in his units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of our units.

The remainder of this discussion assumes that we will be classified as a partnership for U.S. federal income tax purposes.

Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of QR Energy, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as tax partners of QR Energy for U.S. federal income tax purposes. Also, assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners will be treated as partners of QR Energy for U.S. federal income tax purposes. For a discussion related to the risks of losing partner status as a result of short sales, please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales” on page 228. As there is no direct or indirect controlling authority addressing assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, Vinson & Elkins L.L.P.’s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.

Items of our income, gain, loss, or deduction would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. Prospective unitholders are urged to consult their own tax advisors with respect to the consequences of their status as partners in us for U.S. federal income tax purposes.

Flow-Through of Taxable Income

Subject to the discussion below under “— Entity-Level Collections of Unitholder Taxes” on page 227 neither we nor our subsidiaries will pay any U.S. federal income tax. For U.S. federal income tax purposes, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to such unitholder. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for his taxable year or years ending with or within our taxable year. Our taxable year ends on December 31.

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Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of the unitholder’s tax basis in his units generally will be considered to be gain from the sale or exchange of those units, taxable in accordance with the rules described under “— Disposition of Units” on page 235. Any reduction in a unitholder’s share of our liabilities, including as a result of future issuances of additional units or Class B units, will be treated as a distribution of cash to that unitholder. To the extent that cash distributions made by us cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, that unitholder must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses” on page 226.

A non-pro rata distribution of money or property, including a deemed distribution, may result in ordinary income to a unitholder, regardless of that unitholder’s tax basis in its units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, a unitholder will be treated as having received his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for an allocable portion of the distribution made to such unitholder. This latter deemed exchange generally will result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2013, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure our unitholders that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:


	•	gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

	•	we make a future offering of units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

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Basis of Units

A unitholder’s initial tax basis in his units will be the amount he paid for those units plus his share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and by any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by distributions to him, by his share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder’s share of our nonrecourse liabilities will generally be based on the Book-Tax Disparity (as described in “— Allocation of Income, Gain, Loss and Deduction” on page 227) attributable to such unitholder to, the extent of such amount, and, thereafter, his share of our profits. Please read “— Disposition of Units — Recognition of Gain or Loss” on page 235.

Limitations on Deductibility of Losses

The deduction by a unitholder of that unitholder’s share of our losses will be limited to the lesser of (i) the tax basis such unitholder has in his units, and (ii) in the case of an individual, estate, trust or corporate unitholder (if more than 50% of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax exempt organizations) the amount for which the unitholder is considered to be “at risk” with respect to our activities. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause the unitholder’s at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain would not be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of the unitholder’s units, excluding any portion of that basis attributable to the unitholder’s share of our liabilities, reduced by (1) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (2) any amount of money the unitholder borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in the unitholder’s share of our liabilities.

The at-risk limitation applies on an activity-by-activity basis, and in the case of oil and natural gas properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or natural gas property is generally required to be treated separately so that a loss from any one property would be limited to the at-risk amount for that property and not the at-risk amount for all the taxpayer’s oil and natural gas properties. It is uncertain how this rule is implemented in the case of multiple oil and natural gas properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or natural gas properties we own in computing a unitholder’s at-risk limitation with respect to us. If a unitholder were required to compute his at-risk amount separately with respect to each oil or natural gas property we own, he might not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at-risk amount with respect to his units as a whole.

In addition to the basis and at risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the

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extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly-traded partnerships, or a unitholder’s salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss limitations are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that net passive income earned by a publicly-traded partnership will be treated as investment income to its unitholders for purposes of the investment interest expense limitation. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any U.S. federal, state, local or non-U.S. tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. However, at any time that distributions are made to the units in excess of distributions to the subordinated units, or incentive distributions are made, gross income will be allocated to the recipients to the extent of these distributions.

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Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of this offering and any future offerings or certain other transactions, referred to in this discussion as “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder acquiring units in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. However, in connection with providing this benefit to any future unitholders, similar allocations, will be made to all holders of partnership interests immediately prior to such other transactions, including purchasers of units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction.

In the event we issue additional units or engage in certain other transactions, “Reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all persons who are holders of units immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or other transactions. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for U.S. federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

Treatment of Short Sales

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, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions may be subject to tax as ordinary income.

Vinson & Elkins has not rendered an opinion regarding the tax treatment of a unitholder whose units are loaned to a short seller to cover a short sale of our units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “— Disposition of Units — Recognition of Gain or Loss” on page 235.

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Alternative Minimum Tax

Each unitholder will be required to take into account the unitholder’s distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors with respect to the impact of an investment in our units on their liability for the alternative minimum tax.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2011, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

The recently enacted Health Care and Education Reconciliation Act of 2010 and the Patient Protection and Affordable Care Act of 2010 is scheduled to impose a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse) or $200,000 (if the unitholder is unmarried). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect the unitholder’s purchase price. The Section 743(b) adjustment separately applies to any transferee of a unitholder who purchases outstanding units from another unitholder based upon the values and bases of our assets at the time of the transfer to the transferee. The Section 743(b) adjustment does not apply to a person who purchases units directly from us, and belongs only to the purchaser and not to other unitholders. Please read, however, “— Allocation of Income, Gain, Loss and Deduction” on page 227. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) the unitholder’s share of our tax basis in our assets (“common basis”) and (2) the unitholder’s Section 743(b) adjustment to that basis.

The timing and calculation of deductions attributable to Section 743(b) adjustments to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Internal Revenue Code Section 704(c) type gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Internal Revenue Code Section 704(c) principles with respect to an asset to which the adjustment is applicable. Please read “— Allocation of Income, Gain, Loss and Deduction” on page 227.

The timing of these deductions may affect the uniformity of our units. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations or if the position would result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units” on page 237. Vinson & Elkins is unable to opine as

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to the validity of any such alternate tax positions because there is no clear applicable authority. A unitholder’s basis in a unit is reduced by his share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in his units and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Uniformity of Units” on page 237.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and the transferee’s share of any gain or loss on a sale of assets by us would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the fair market value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally either non-amortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure our unitholders that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should our general partner determine the expense of compliance exceeds the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than such purchaser would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Units — Allocations Between Transferors and Transferees” on page 236.

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above (please read “— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses” on page 226), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas interests. Although the Internal Revenue Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes. Each unitholder, however, remains responsible for calculating his own depletion allowance and maintaining

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records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative contracts or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s average net daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. Moreover, the availability of percentage depletion may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “— Recent Legislative Developments” on page 233. We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and

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necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and natural gas wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in oil or natural gas properties and also carries on substantial retailing or refining operations. An oil or natural gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. To qualify as an “independent producer” that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of oil and natural gas products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read “— Disposition of Units — Recognition of Gain or Loss” on page 235.

The election to currently deduct IDCs may be restricted or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “— Recent Legislative Developments’’ on page 233.

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to 6% of our qualified production activities income that is allocated to such unitholder, but not to exceed 50% of such unitholder’s IRS Form W-2 wages for the taxable year allocable to domestic production gross receipts.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him

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from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read “— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses” on page 226.

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Moreover, the availability of Section 199 deductions may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “— Recent Legislative Developments” on page 233. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs

The cost of acquiring oil and natural gas lease or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “— Tax Treatment of Operations — Depletion Deductions” on page 230.

Geophysical Costs

The cost of geophysical exploration incurred in connection with the exploration and development of oil and natural gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Recent Legislative Developments

The White House recently released President Obama’s budget proposal for the Fiscal Year 2011 (the “Budget Proposal”). Among the changes recommended in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences relating to oil and natural gas exploration and development. Changes in the Budget Proposal 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

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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.

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our partners holding interest in us prior to this offering. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” on page 227.

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. We may not be entitled to any amortization deductions with respect to certain goodwill properties conveyed to us or held by us at the time of any future offering. Please read “— Uniformity of Units” on page 237. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” on page 227 and “— Disposition of Units — Recognition of Gain or Loss” on page 235.

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

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Disposition of Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our liabilities. Because the amount realized includes a unitholder’s share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in the unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2010 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion or IDC recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

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Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly-traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly-traded partnerships are entitled to rely on those proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until the final Treasury Regulations are issued. Accordingly, Vinson & Elkins is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have terminated our tax partnership for U.S. federal income tax purposes upon the sale or exchange of interests in QR Energy that, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% has been met, multiple sales of the same unit are counted only once. A constructive

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termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. However, pursuant to an IRS relief procedure for publicly traded partnerships that have technically terminated, the IRS may allow, among other things, that we provide a single Schedule K-1 for the tax year in which a termination occurs. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units and because of other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity could result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6) and Treasury Regulation Section 1.197-2(g)(3), neither of which is anticipated to apply to a material portion of our assets. Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election” on page 229.

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units even under circumstances like those described above. These positions may include reducing for some unitholders the depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins is unable to opine as to validity of such filing positions. A unitholder’s basis in units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in his units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Units — Recognition of Gain or Loss” on page 235 and “— Tax Consequences of Unit Ownership — Section 754 Election” on page 229. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they

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will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we, nor Vinson & Elkins can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to his returns.

Partnerships generally are treated as separate entities for purposes of U.S. federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax

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treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement designates our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2) a statement regarding whether the beneficial owner is:

(a) a person that is not a U.S. person;

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

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For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, “substantial authority;” or

(2) as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the relevant facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly our unitholders and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single tax year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly our unitholders’ tax return) would be audited by the IRS. Please read “— Administrative Matters — Information Returns and Audit Procedures” on page 238.

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, our unitholders may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described in “— Accuracy-Related Penalties” on page 239;

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

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State, Local and Other Tax Considerations

In addition to U.S. federal income taxes, unitholders will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or owns property or in which the unitholder is a resident. We currently conduct business or own property in several states, most of which impose personal income taxes on individuals. Most of these states also impose an income tax on corporations and other entities. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. A unitholder may be required to file state income tax returns and to pay state income taxes in any state in which we do business or own property, and such unitholder may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections of Unitholder Taxes” on page 227. Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Vinson & Elkins has not rendered an opinion on the state, local, or non-U.S. tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax returns that may be required of him.

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INVESTMENT IN QR ENERGY, LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities (“IRAs”) established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements. Among other things, consideration should be given to:


	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

	•	whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors” on page 237; and

	•	whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets.” Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:


	•	the equity interests acquired by the employee benefit plan are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

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	•	the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

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

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in the first two bullet points above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

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UNDERWRITING

Subject to the terms and conditions set forth in an underwriting agreement, we have agreed to sell to the underwriters named below, and the underwriters, for whom Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC are acting as joint-book running managers and representatives, have severally agreed to purchase, the respective number of common units appearing opposite their names below:


	Number of
Underwriter	Common Units

Wells Fargo Securities, LLC		2,812,500
J.P. Morgan Securities LLC		2,812,500
Raymond James & Associates, Inc.		2,812,500
RBC Capital Markets, LLC		2,812,500
Robert W. Baird & Co. Incorporated		750,000
Credit Suisse Securities (USA) LLC		750,000
Deutsche Bank Securities Inc.		750,000
Oppenheimer & Co. Inc.		750,000
Stifel, Nicolaus & Company, Incorporated		750,000

Total		15,000,000

All of the common units to be purchased by the underwriters will be purchased from us.

The underwriting agreement provides that the obligations of the several underwriters are subject to various conditions, including approval of legal matters by counsel. The common units are offered by the underwriters, subject to prior sale, when, as and if issued to and accepted by them. The underwriters reserve the right to withdraw, cancel or modify the offer and to reject orders in whole or in part.

The underwriting agreement provides that the underwriters are obligated to purchase all the common units offered by this prospectus if any are purchased, other than those common units covered by the over-allotment option described below. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the non-defaulting underwriters may be increased or the underwriting agreement may be terminated.

Option to Purchase Additional Common Units

We have granted the underwriters an option, exercisable for 30 days after the date of the underwriting agreement, to purchase up to an additional 2,250,000 common units from us at the initial public offering price less the underwriting discounts, as set forth on the cover page of this prospectus, and less any dividends or distributions declared, paid or payable on the common units that the underwriters have agreed to purchase from us but that are not payable on such additional common units, to cover over-allotments, if any. If the underwriters exercise this option in whole or in part, then the underwriters will be severally committed, subject to the conditions described in the underwriting agreement, to purchase the additional common units in proportion to their respective commitments set forth in the prior table.

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.

Discounts

The common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus and to certain dealers at that price less a

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concession of not more than $0.78 per common unit. After the initial offering, the public offering price, concession and reallowance to dealers may be changed.

The following table summarizes the underwriting discounts and the proceeds, before expenses, payable to us, both on a per unit basis and in total, assuming either no exercise or full exercise by the underwriters of their option to purchase additional common units:


			Total
	Per Common		Without		With
	Unit		Option		Option

Public offering price	$	20.00	$	300,000,000	$	345,000,000
Underwriting discounts	$	1.30	$	19,500,000	$	22,425,000
Proceeds, before expenses, to us	$	18.70	$	280,500,000	$	322,575,000

We estimate that the expenses of this offering payable by us, not including underwriting discounts and structuring fees, will be approximately $4,750,000. We will pay Wells Fargo Securities, LLC a structuring fee equal to 0.25% of the gross proceeds of this offering for the evaluation, analysis and structuring of our partnership.

Indemnification of Underwriters

The underwriting agreement provides that we will indemnify the underwriters against specified liabilities, including liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in respect of those liabilities.

Lock-Up Agreements

We, our general partner and certain of its affiliates, the directors and executive officers of our general partner, and each participant in the directed unit program who are family members of the directors and executive officers of our general partner or who purchases in excess of $100,000 worth of reserved units have agreed, subject to certain exceptions, that, without the prior written consent of Wells Fargo Securities, LLC, we and they will not, during the period beginning on and including the date of this prospectus through and including the date that is the 180th day after the date of this prospectus, directly or indirectly:


	•	issue (in the case of us), offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of any of our common units or any securities convertible into or exercisable or exchangeable for our common units, except that we may issue common units or any securities convertible or exchangeable into our common units as payment of any part of the purchase price for businesses that we acquire; provided that any recipient of such common units must agree in writing to be bound by these provisions for the remainder of the lock-up period;

	•	in the case of us, file or cause the filing of any registration statement under the Securities Act with respect to any of our common units or any securities convertible into or exercisable or exchangeable for our common units (other than (i) any Rule 462(b) registration statement filed to register securities to be sold to the underwriters pursuant to the underwriting agreement, (ii) any registration statement on Form S-8 to register common units or options to purchase common units pursuant to the long-term incentive plan, and (iii) any registration statement in connection with our entrance into a definitive agreement relating to an acquisition; or

	•	enter into any swap or other agreement, arrangement, hedge or transaction that transfers to another, in whole or in part, directly or indirectly, any of the economic consequences of ownership of our common units or any securities convertible into or exercisable or exchangeable for our common units,

245

whether any transaction described in any of the foregoing bullet points is to be settled by delivery of our common units, other securities, in cash or otherwise; or publicly announce an intention to do any of the foregoing. Moreover, if:


	•	during the last 17 days of the lock-up period, we issue an earnings release or material news or a material event relating to us occurs; or

	•	prior to the expiration of the lock-up period, we announce that we will release earnings results or become aware that material news on a material event relating to us will occur during the 16-day period beginning on the last day of the lock-up period,

the restrictions described in the immediately preceding sentence will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event, as the case may be, unless Wells Fargo Securities, LLC waives, in writing, that extension.

Wells Fargo Securities, LLC may, in its sole discretion and at any time or from time to time, without notice, release all or any portion of the common units or other securities subject to the lock-up agreements. Any determination to release any common units or other securities subject to the lock-up agreements would be based on a number of factors at the time of determination, which may include the market price of the common units, the liquidity of the trading market for the common units, general market conditions, the number of common units or other securities proposed to be sold or otherwise transferred and the timing, purpose and terms of the proposed sale or other transfer.

Electronic Distribution

This prospectus and the registration statement of which this prospectus forms a part may be made available in electronic format on the websites maintained by one or more of the underwriters. The underwriters may agree to allocate a number of common units for sale to their online brokerage account holders. The common units will be allocated to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

Other than the information set forth in this prospectus and the registration statement of which this prospectus forms a part, information contained in any website maintained by an underwriter is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been endorsed by us and should not be relied on by investors in deciding whether to purchase common units. The underwriters are not responsible for information contained in websites that they do not maintain.

New York Stock Exchange

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.” The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange distribution requirements for trading.

Stabilization

In order to facilitate this offering of our common units, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the market price of our common units. Specifically, the underwriters may sell more common units than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is covered if the short position is no greater than the number of common units available for purchase by the underwriters under their option to purchase additional common units. The underwriters may close out a covered short sale by exercising their option to purchase additional common units or purchasing common units in the open market. In determining the source of common units to close out a covered short sale, the underwriters may consider, among other things, the market price of common units compared to the price payable under

246

their option to purchase additional common units. The underwriters may also sell common units in excess of the number of common units available under their option to purchase additional common units, creating a naked short position. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after the date of pricing of this offering that could adversely affect investors who purchase in this offering.

As an additional means of facilitating this offering, the underwriters may bid for, and purchase, common units in the open market to stabilize the price of our common units, so long as stabilizing bids do not exceed a specified maximum. The underwriting syndicate may also reclaim selling concessions allowed to an underwriter or a dealer for distributing common units in this offering if the underwriting syndicate repurchases previously distributed common units to cover syndicate short positions or to stabilize the price of the common units.

The foregoing transactions, if commenced, may raise or maintain the market price of our common stock above independent market levels or prevent or retard a decline in the market price of the common stock.

The foregoing transactions, if commenced, may be effected on the New York Stock Exchange or otherwise. Neither we nor any of the underwriters makes any representation that the underwriters will engage in any of these transactions and these transactions, if commenced, may be discontinued at any time without notice. Neither we nor any of the underwriters makes any representation or prediction as to the direction or magnitude of the effect that the transactions described above, if commenced, may have on the market price of our common stock.

Discretionary Accounts

The underwriters have informed us that they do not intend to confirm sales to accounts over which they exercise discretionary authority in excess of 5% of the total number of common units offered by them.

Pricing of This Offering

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for our common units was determined between us and the representatives of the underwriters. The factors considered in determining the initial public offering price included:


	•	prevailing market conditions;

	•	our results of operations and financial condition;

	•	financial and operating information and market valuations with respect to other companies that we and the representative of the underwriters believe to be comparable or similar to us;

	•	the present state of our development; and

	•	our future prospects.

An active trading market for our common units may not develop. It is possible that the market price of our common units after this offering will be less than the initial public offering price.

Directed Unit Program

At our request, the underwriters have reserved up to 5% of the common units being offered by this prospectus for sale at the initial public offering price to the officers, directors and employees of our general partner and its affiliates and certain other persons associated with us, as designated by us. The sales will be made by Wells Fargo Securities, LLC through a directed unit program. The number of units available for sale to the general public will be reduced to the extent that these individuals purchase all

247

or a portion of the reserved units. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. We have agreed to indemnify Wells Fargo Securities, LLC and the underwriters in connection with the directed unit program, including for the failure of any participant to pay for its units.

Relationships

Certain of the underwriters and their affiliates have provided, and may in the future provide, various investment banking, commercial banking, financial advisory and other financial services to us and our affiliates for which they have received, and may in the future receive, customary fees. Additionally, certain of the underwriters and their affiliates have engaged, and may from time to time in the future engage, in transactions with us in the ordinary course of their business. Affiliates of Wells Fargo Securities, LLC, J.P. Morgan Securities LLC, and RBC Capital Markets, LLC are lenders under three separate credit facilities of the Fund and certain of its affiliates and will receive a portion of the net proceeds from this offering pursuant to payments made by us to the Fund and certain of its affiliates as partial consideration for the contribution of the Partnership Properties. For a description of the existing credit facilities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Predecessor Liquidity and Capital Resources — The Fund’s Credit Facilities” on page 133.

This offering is being made in compliance with Rule 2310 of the Financial Industry Regulatory Authority, Inc., or FINRA, Rules. In no event will the maximum amount of compensation to be paid to FINRA members in connection with this offering exceed 10% of the offering proceeds. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

248

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered by us will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.

EXPERTS

The balance sheet of QR Energy, LP as of September 20, 2010 included in this prospectus has been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements of QA Holdings, LP as of December 31, 2009 and for the year ended December 31, 2009 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements of QA Holdings, LP as of December 31, 2008 and for each of the years in the two-year period ended December 31, 2008, have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses of the Encore properties which were acquired from Denbury Resources, Inc. by Quantum Resources Management, LLC for the years ended December 31, 2007, 2008 and 2009, included in this prospectus, have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The statements of revenues and direct operating expenses for EXCO Resources, Inc.’s divested properties subsequently acquired by Quantum Resources Management, LLC for the years ended December 31, 2007 and December 31, 2008; and the period from January 1, 2009 to August 11, 2009, have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

Estimated quantities of our oil and natural gas reserves and the net present value of such reserves as of June 30, 2010 set forth in this prospectus are based upon reserve reports prepared by us and audited by Miller and Lents, Ltd.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-l regarding the units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. The registration statement, of which this prospectus forms a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years. Additionally, we intend to file periodic reports with the SEC, as required by the Securities Exchange Act of 1934.

249

FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:


	•	business strategies;

	•	ability to replace the reserves we produce through drilling and property acquisitions;

	•	drilling locations;

	•	oil and natural gas reserves;

	•	technology;

	•	realized oil and natural gas prices;

	•	production volumes;

	•	lease operating expenses;

	•	general and administrative expenses;

	•	future operating results; and

	•	plans, objectives, expectations and intentions.

These types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in “Prospectus Summary,” “Risk Factors,” “Our Cash Distribution Policy and Restrictions on Distributions,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business and Properties” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the “Risk Factors” section beginning on page 29 and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

250

QR Energy, LP

Unaudited Pro Forma Condensed Financial Statements

Introduction

The following unaudited pro forma condensed financial statements of QR Energy, LP (“QR Energy”) reflect the unaudited and audited historical results of QA Holdings, LP (the “Predecessor”) on a pro forma basis to give effect to the “Denbury Acquisition,” the “Contribution” and the “Offering.” These transactions are described below.

The Denbury Acquisition. Quantum Resources Management LLC, a wholly owned subsidiary of the Predecessor, signed a purchase and sale agreement on March 31, 2010 to acquire certain oil and natural gas properties from Denbury Resources, Inc. for $893 million with an effective date of May 1, 2010. The Denbury assets are reflective of oil and natural gas properties accumulated through a series of acquisitions including Denbury’s March 4, 2010 acquisition of Encore Acquisition Corporation (the “Denbury Acquisition Encore Assets”), and certain oil and natural gas properties of Exco Resources, Inc. acquired by Encore on August 11, 2009, prior to Denbury’s acquisition of Encore (the “Denbury Acquisition Exco Assets”). The transaction closed on May 14, 2010 and was funded with cash from the proceeds of a combination of equity contributions (cash calls to the Fund’s partners) and debt. The preliminary purchase price allocation of the Denbury Acquisition has been reflected in the unaudited historical consolidated balance sheet of the Predecessor as of September 30, 2010.

The purchase price allocation reflecting the Denbury Acquisition under the acquisition method of accounting is preliminary and includes the use of estimates and assumptions as described in the related notes to the unaudited historical consolidated financial statements of the Predecessor, included elsewhere in this prospectus. The preliminary purchase price allocation is based on information available to management at the time the unaudited historical consolidated financial statements of the Predecessor were prepared. Management believes the estimates and assumptions used are reasonable and the significant effects of the transaction are properly reflected in the unaudited historical consolidated financial statements of the Predecessor. However, the purchase price allocation is considered preliminary and subject to adjustment until the final closing statement is completed. Management expects to complete its purchase price allocation during the fourth quarter of 2010.

The Contribution. Effective upon the closing of this offering, the Predecessor will contribute selected oil and natural gas interests and related operations along with certain derivative contracts to QR Energy in exchange for a combination of QR Energy common, subordinated and general partner units and cash.

The Offering. For purposes of the unaudited pro forma condensed financial statements, the Offering is defined as the issuance and sale to the public of common units of QR Energy for $300 million, the borrowing of $225 million under a new revolving credit facility and the application by QR Energy of the net proceeds from such issuance and borrowing as described in “Use of Proceeds” on page 66.

The unaudited pro forma condensed balance sheet of QR Energy is based on the unaudited historical consolidated balance sheet of the Predecessor and includes pro forma adjustments to give effect to the Contribution and the Offering as if they occurred on September 30, 2010.

The unaudited pro forma condensed statements of operations of QR Energy are based on the unaudited historical consolidated statements of operations of the Predecessor for the nine months ended September 30, 2010 and 2009 and the audited historical consolidated statement of operations of the Predecessor for the year ended December 31, 2009, each period having been adjusted to give effect to the Denbury Acquisition, the Contribution and the Offering as if they occurred on January 1, 2009.

The unaudited pro forma condensed financial statements have been prepared on the basis that QR Energy will be treated as a partnership for federal income tax purposes. The unaudited pro forma

F-2

condensed financial statements should be read in conjunction with the notes accompanying these unaudited pro forma condensed financial statements and with the unaudited and audited historical consolidated financial statements and related notes of the Predecessor, found elsewhere in this prospectus.

The pro forma adjustments to the unaudited and audited historical financial statements are based upon currently available information and certain estimates and assumptions. The actual effect of the transactions discussed in the accompanying notes ultimately may differ from the unaudited pro forma adjustments included herein. However, management believes that the assumptions utilized to prepare the pro forma adjustments provide a reasonable basis for presenting the significant effects of the transactions as currently contemplated and that the unaudited pro forma adjustments are factually supportable, give appropriate effect to the expected impact of events that are directly attributable to the transactions, and reflect those items expected to have a continuing impact on QR Energy.

The unaudited pro forma condensed financial statements of QR Energy are not necessarily indicative of the results that actually would have occurred if QR Energy had completed the Denbury Acquisition, the Contribution or the Offering on the dates indicated or which could be achieved in the future due to the omission of various operating expenses. Production and reserves, as well as costs and expenses, associated with the Denbury Acquisition properties as operated by the Predecessor differ significantly from those characteristics when such properties were operated by Encore Acquisition Corporation and Exco Resources, Inc. During the periods presented, the Denbury Acquisition properties were not accounted for by Encore and Exco as a separate entity. As such, certain costs, such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses and interest expense were not allocated to the Denbury Properties.

F-3

QR ENERGY, LP

UNAUDITED PRO FORMA CONDENSED BALANCE SHEET
SEPTEMBER 30, 2010
(In thousands)


			Predecessor						Offering			Partnership
	Predecessor		Retained			Partnership			Related			Pro forma
	Historical		Operations(a)			Pro Forma			Adjustments			As Adjusted

ASSETS:
Current assets:
Cash and cash equivalents	$	21,340	$	(21,340	)	$	—		$	225,000	(f)	$	—
										300,000	(g)
										(200,000	)(h)
										(300,000	)(h)
										(25,000	)(i)
Accounts receivable:
Trade and other, net of allowance for doubtful accounts		4,013		(4,013	)		—			—			—
Oil and natural gas sales		41,395		(41,395	)		—			—			—
Due from Affiliates		739		(739	)		—			—			—
Derivative instruments		20,971		(8,750	)		12,221	(b)		—			12,221
Prepaid and current assets		2,430		(2,430	)		—			—			—

Total current assets		90,888		(78,667	)		12,221			—			12,221
Property and Equipment, net		1,044,752		(667,039	)		377,713	(c)		—			377,713
Other assets:
Investment in UTE Energy, LLC		47,151		(47,151	)		—			—			—
Property reclamation deposit		10,730		(10,730	)		—			—			—
Inventories		5,507		(5,507	)		—			—			—
Derivative Instruments		34,347		(22,653	)		11,694	(b)		—			11,694
Deferred financing costs, net of amortization		10,869		(10,869	)		—			3,000	(i)		3,000
Other long-term assets		1,549		(1,549	)		—			—			—

Total other assets		110,153		(98,459	)		11,694			3,000			14,694

Total assets	$	1,245,793	$	(844,165	)	$	401,628		$	3,000		$	404,628


LIABILITIES AND PARTNERS CAPITAL:
Current liabilities:
Accounts payable	$	1,002	$	(1,002	)	$	—		$	—		$	—
Oil and natural gas payable		6,560		(6,560	)		—			—			—
Current portion of asset retirement obligations		1,676		(1,676	)		—			—			—
Derivative instruments		24,304		(24,304	)		—						—
Accrued and other liabilities		33,375		(33,375	)		—			—			—

Total current liabilities		66,917		(66,917	)		—			—			—
Long-term debt		547,668		(347,668	)		200,000	(e)		225,000	(f)		225,000
										(200,000	)(h)

Derivative instruments		67,474		(59,979	)		7,495	(b)					7,495
Asset retirement obligations		62,052		(48,421	)		13,631	(d)		—			13,631
Long term capital lease		63		(63	)		—			—			—
Other long-term liability		2,272		(2,272	)		—			—			—
Partners’ capital:
Partners’ capital		16,795		163,707			380,502	(e)		300,000	(g)		158,502
							(200,000	)(e)		(300,000	)(h)
										(22,000	)(i)

Total partners’ capital		16,795		163,707			180,502			(22,000	)		158,502
Noncontrolling interest		482,552		(482,552	)		—			—			—

Total Equity		499,347		(318,845	)		180,502			(22,000	)		158,502

Total liabilities and equity	$	1,245,793	$	(844,165	)	$	401,628		$	3,000		$	404,628

See accompanying notes to the unaudited pro forma condensed financial statements.

F-4

QR ENERGY, LP

UNAUDITED PRO FORMA CONDENSED STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010
(In thousands, except per unit amounts)


				Denbury
				Acquisition								Predecessor						Offering			Partnership
	Predecessor			Encore		Pro Forma			Predecessor			Retained			Partnership			Related			Pro forma
	Historical			Assets(j)		Adjustments			Pro Forma			Operations(a)			Pro Forma			Adjustments			As Adjusted

Revenues:
Oil and natural gas sales	$	170,647		$	89,804	$	—		$	260,451		$	(186,143	)	$	74,308	(p)	$	—		$	74,308
Processing		4,823			—		—			4,823			(4,823	)		—			—			—

Total revenues		175,470			89,804		—			265,274			(190,966	)		74,308			—			74,308
Operating Expenses:
Lease operating		52,152			17,476		—			69,628			(54,386	)		15,242	(p)		—			15,242
Production taxes		12,528			4,674		—			17,202			(13,877	)		3,325	(p)		—			3,325
Processing		2,985			—		—			2,985			(2,985	)		—			—			—
Transportation		891			1,112		—			2,003			(1,066	)		937	(p)		—			937
Depreciation, depletion and amortization		45,149			—		18,359	(l)		63,508			(45,192	)		18,316	(r)		—			18,316
Accretion of asset retirement obligations		2,648			—		1,240	(m)		3,888			(3,066	)		822	(s)		—			822
Management fees		7,885			—		—			7,885			(7,885	)		—			—			—
Acquisition evaluation costs		1,197			—		—			1,197			(1,197	)		—			—			—
General and administrative		19,176			—		1,758	(n)		20,934			(11,798	)		9,136	(t)		3,193	(v)		12,329
Other expense		224			—		—			224			(224	)		—			—			—

Total operating expenses		144,835			23,262		21,357			189,454			(141,676	)		47,778			3,193			50,971
Income (loss) from operations		30,635			66,542		(21,357	)		75,820			(49,290	)		26,530			(3,193	)		23,337
Other income (expenses):
Interest income		27			—		—			27			(27	)		—			—			—
Realized gains on commodity derivative contracts		5,132			—		—			5,132			(3,039	)		2,093	(u)		—			2,093
Unrealized gains (losses) on commodity derivative contracts		41,432			—		—			41,432			(24,538	)		16,894	(u)		—			16,894
Interest expense		(31,392	)		—		(4,839	)(o)		(36,231	)		36,231			—			(5,827	)(w)		(5,827	)
Other income (expense)		5,147			—		—			5,147			(5,147	)		—			—			—

Total other income (expenses)		20,346			—		(4,839	)		15,507			3,480			18,987			(5,827	)		13,160

Net Income (loss)	$	50,981		$	66,542	$	(26,196	)	$	91,327		$	(45,810	)	$	45,517		$	(9,020	)	$	36,497

Computation of net income per limited partner unit:
General partner’s interest in net income																					$	36

Limited partners’ interest in net income																					$	36,461

Net income per limited partner unit																					$	1.02

Weighted average number of limited partner units outstanding																						35,694

See accompanying notes to the unaudited pro forma condensed financial statements.

F-5

QR ENERGY, LP

UNAUDITED PRO FORMA CONDENSED STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009
(In thousands, except per unit amounts)


				Denbury		Denbury
				Acquisition		Acquisition								Predecessor						Offering			Partnership
	Predecessor			Encore		Exco		Pro Forma			Predecessor			Retained			Partnership			Related			Pro forma
	Historical			Assets(j)		Assets(k)		Adjustments			Pro Forma			Operations(a)			Pro Forma			Adjustments			As Adjusted

Revenues:
Oil and natural gas sales	$	49,071		$	77,467	$	36,451	$	—		$	162,989		$	(109,641	)	$	53,348	(p)	$	—		$	53,348
Processing		4,007			—		—		—			4,007			(4,007	)		—			—			—

Total revenues		53,078			77,467		36,451		—			166,996			(113,648	)		53,348			—			53,348
Operating Expenses:
Lease operating		23,724			18,440		7,426		—			49,590			(32,700	)		16,891	(p)		—			16,891
Production taxes		4,975			3,747		3,546		—			12,268			(9,386	)		2,882	(p)		—			2,882
Processing		2,293			—		—		—			2,293			(2,293	)		—			—			—
Transportation		662			1,323		3,098		—			5,083			(3,939	)		1,144	(p)		—			1,144
Impairment of oil and gas properties		28,338			—		—		—			28,338			(14,426	)		13,912	(q)		—			13,912
Depreciation, depletion and amortization		13,743			—		—		49,602	(l)		63,345			(45,029	)		18,316	(r)		—			18,316
Accretion of asset retirement obligations		2,847			—		—		1,166	(m)		4,013			(3,396	)		617	(s)		—			617
Management fees		9,013			—		—		—			9,013			(9,013	)		—			—			—
Acquisition evaluation costs		7			—		—		—			7			(7	)		—			—			—
General and administrative		12,916			—		—		1,758	(n)		14,674			(8,090	)		6,583	(t)		3,193	(v)		9,776
Bargain purchase gain		(1,200	)		—		—		—			(1,200	)		1,200			—			—			—

Total operating expenses		97,318			23,510		14,070		52,526			187,424			(127,079	)		60,345			3,193			63,538
Income (loss) from operations		(44,240	)		53,957		22,381		(52,526	)		(20,428	)		13,431			(6,997	)		(3,193	)		(10,190	)
Other income (expenses):
Interest income		32			—		—		—			32			(32	)		—			—			—
Realized gains on commodity derivative contracts		42,177			—		—		—			42,177			(21,441	)		20,736	(u)		—			20,736
Unrealized gains (losses) on commodity derivative contracts		(74,123	)		—		—		—			(74,123	)		37,681			(36,442	)(u)		—			(36,442	)
Interest expense		(2,939	)		—		—		(12,299	)(o)		(15,238	)		15,237			—			(5,827	)(w)		(5,827	)
Other income (expense)		2,240			—		—		—			2,240			(2,240	)		—			—			—

Total other income (expenses)		(32,613	)		—		—		(12,299	)		(44,912	)		29,205			15,706			(5,827	)		(21,533	)

Net Income (loss)	$	(76,853	)	$	53,957	$	22,381	$	(64,825	)	$	(65,340	)	$	42,636		$	(22,703	)	$	(9,020	)	$	(31,723	)

Computation of net income per limited partner unit:
General partner’s interest in net loss																							$	(32	)

Limited partners’ interest in net loss																							$	(31,691	)

Weighted average number of limited partner units outstanding																							$	(0.89	)

																								35,694

See accompanying notes to the unaudited pro forma condensed financial statements.

F-6

QR ENERGY, LP

UNAUDITED PRO FORMA CONDENSED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2009
(In thousands, except per unit amounts)


				Denbury		Denbury
				Acquisition		Acquisition								Predecessor						Offering			Partnership
	Predecessor			Encore		Exco		Pro Forma			Predecessor			Retained			Partnership			Related			Pro forma
	Historical			Assets(j)		Assets(k)		Adjustments			Pro Forma			Operations(a)			Pro Forma			Adjustments			As Adjusted

Oil and natural gas sales	$	69,193		$	124,526	$	36,451	$	—		$	230,170		$	(153,266	)	$	76,904	(p)	$	—		$	76,904
Processing		3,608			—		—		—			3,608			(3,608	)		—			—			—

Total revenues		72,801			124,526		36,451		—			233,778			(156,874	)		76,904			—			76,904
Operating Expenses:
Lease operating		33,328			28,758		7,426		—			69,512			(45,729	)		23,783	(p)		—			23,783
Production taxes		7,587			9,903		3,546		—			21,036			(15,272	)		5,764	(p)		—			5,764
Processing		3,045			—		—		—			3,045			(3,045	)		—			—			—
Transportation		881			2,142		3,098		—			6,121			(4,587	)		1,534	(p)		—			1,534
Impairment of oil and gas properties		28,338			—		—		—			28,338			(14,426	)		13,912	(q)		—			13,912
Depreciation, depletion and amortization		16,993			—		—		65,479	(l)		82,472			(58,072	)		24,400	(r)		—			24,400
Accretion of asset retirement obligations		3,585			—		—		1,567	(m)		5,152			(4,325	)		827	(s)		—			827
Management fees		12,018			—		—		—			12,018			(12,018	)		—			—			—
Acquisition evaluation costs		582			—		—		—			582			(582	)		—			—			—
General and administrative		18,879			—		—		2,344	(n)		21,223			(14,213	)		7,010	(t)		4,258	(v)		11,268
Bargain purchase gain		(1,200	)		—		—		—			(1,200	)		1,200			—			—			—

Total operating expenses		124,036			40,803		14,070		69,390			248,299			(171,069	)		77,230			4,258			81,488
Income (loss) from operations		(51,235	)		83,723		22,381		(69,390	)		(14,521	)		14,195			(326	)		(4,258	)		(4,584	)
Other income (expenses):
Interest income		37			—		—		—			37			(37	)		—			—			—

Realized gains (losses) on commodity derivative contracts		47,993			—		—		—			47,993			(24,398	)		23,595	(u)		—			23,595
Unrealized gains (losses) on commodity derivative contracts		(111,113	)		—		—		—			(111,113	)		56,485			(54,628	)(u)		—			(54,628	)
Interest expense		(3,753	)		—		—		(16,262	)(o)		(20,015	)		20,015			—			(7,770	)(w)		(7,770	)
Other expense		2,657			—		—		—			2,657			(2,657	)		—			—			—

Total other expenses		(64,179	)		—		—		(16,262	)		(80,441	)		49,408			(31,033	)		(7,770	)		(38,803	)

Net income (loss)	$	(115,414	)	$	83,723	$	22,381	$	(85,652	)	$	(94,962	)	$	63,603		$	(31,359	)	$	(12,028	)	$	(43,387	)

Computation of net income per limited partner unit:
General partner’s interest in net loss																							$	(43	)

Limited partners’ interest in net loss																							$	(43,344	)

Net loss per limited partner unit																							$	(1.21	)

Weighted average number of limited partner units outstanding																								35,694

See accompanying notes to the unaudited pro forma condensed financial statements.

F-7

QR ENERGY, LP

NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS


Note 1 —	Basis of Presentation

The unaudited pro forma condensed balance sheet of QR Energy, LP (“QR Energy”) as of September 30, 2010, is based on the unaudited historical consolidated balance sheet of the Predecessor and includes pro forma adjustments to give effect to the Contribution and the Offering as if they occurred on September 30, 2010.

The unaudited pro forma condensed statements of operations of QR Energy are based on the unaudited historical consolidated statement of operations of the Predecessor for the nine months ended September 30, 2010 and 2009 and the audited historical consolidated statement of operations of the Predecessor for the year ended December 31, 2009, each period having been adjusted for the Denbury Acquisition, the Contribution and the Offering, as described further below.

The Statements of Revenues less Direct Operating Expenses related to the oil and natural gas properties acquired from Denbury are reflective of oil and natural gas properties accumulated through a series of acquisitions including the Predecessor’s acquisition of Denbury on May 14, 2010, Denbury’s March 4, 2010 acquisition of the Denbury Acquisition Encore Assets, and certain oil and natural gas properties of Exco Resources, Inc. acquired by Encore on August 11, 2009, prior to Denbury’s acquisition of Encore.

The unaudited pro forma condensed financial statements give effect to the Denbury Acquisition as follows:


	•	Adjustments to reflect the depreciation, depletion and amortization of the oil and natural gas properties acquired using the full cost method of accounting and corresponding asset retirement obligations as though they were included in the oil and natural gas properties of the Predecessor as of January 1, 2009; and

	•	Adjustments to reflect the Predecessor’s incremental recurring general and administrative expenses associated with the administration of the oil and natural gas properties acquired in the Denbury Acquisition.

The unaudited pro forma condensed financial statements give effect to the Contribution as follows:


	•	The contribution by the Predecessor of selected oil and natural gas interests and related operations to QR Energy;

	•	The contribution by the Predecessor of certain derivative contracts, which will be used to manage exposure to oil and natural gas price volatility related to the production from the contributed oil and natural gas interests to QR Energy;

	•	The retention by the Predecessor of certain oil and natural gas interests and all other assets and liabilities not contributed to QR Energy; and

	•	The issuance by QR Energy of 13,547,737 common units, 7,145,866 subordinated units and 35,729 general partner units and cash as consideration for the contribution of oil and gas interest.

Because the contributed oil and natural gas interests and derivative contracts are owned by the Predecessor and the Predecessor will control QR Energy, the Contribution of these assets to QR Energy has been accounted for as a combination of entities under common control, whereby the assets and liabilities contributed will be recorded based on an estimate of the Predecessor’s historical cost.

The unaudited pro forma condensed financial statements give effect to the Offering as follows:


	•	The issuance and sale by QR Energy of 15,000,000 common units to the public in the initial public offering at an assumed offering price of $20.00 per unit (the midpoint of the range shown

F-8


		on the cover of this prospectus), resulting in gross proceeds to QR Energy of $300 million, before deduction of estimated underwriting discount and related offering expenses of $22 million; and


	•	Borrowings by QR Energy of $225 million under a new $750 million revolving credit facility.


Note 2.	Pro Forma Adjustments and Assumptions

Unaudited pro forma condensed balance sheet

The Contribution

(a) Adjustments to reflect the assets, liabilities, revenues and expenses that will be retained by the Predecessor, and thus will not be contributed to QR Energy. The adjustment was based on either specific identification or an allocation by percentage of the relative fair value of the oil and natural gas assets contributed and the relative fair value of the oil and natural gas properties retained, as further explained in each footnote below. The allocation percentage was applied to the historic basis of each account.

Additionally, certain financial statement line items including, (i) equity in earnings of Ute Energy, LLC, (ii) dividends on investment in marketable equity securities, (iii) realized losses on investment in marketable equity securities, (iv) unrealized gains on investment in marketable equity securities and (v) gain on equity share issuance have been condensed into other income (expense) as these results of operations will be retained by the Predecessor, and thus will not be contributed to QR Energy.

(b) Adjustment to reflect specifically identified commodity derivative contracts to be contributed to QR Energy by the Predecessor at the closing of the Offering.

(c) Pro forma adjustment to reflect the oil and natural gas interests to be contributed to QR Energy by the Predecessor. The net book value of the Predecessor’s oil and gas properties, using the full cost method of accounting (for further discussion see the “Property and Equipment” note to audited historical consolidated financial statements, found elsewhere in this prospectus), have been allocated between QR Energy and the Predecessor based on a percentage of the relative fair value of the respective properties to be contributed to QR Energy and to be retained by the Predecessor applied to their net book value.

(d) Pro forma adjustment to reflect the asset retirement obligation associated with the oil and natural gas interests to be contributed to QR Energy by the Predecessor.

(e) Pro forma adjustment to reflect the issuance by QR Energy of 13,547,737 common units, 7,145,866 subordinated units and 35,729 general partner units to the Predecessor as consideration for the contribution of oil and natural gas interests and derivative contracts and assumption of $200 million in debt of the Fund.

The Offering

(f) Pro forma adjustment to reflect the cash proceeds related to borrowings by QR Energy of $225 million under a new $750 million revolving credit facility. Pro forma adjustments have not been made to assume a portion of the Fund’s debt that currently burdens the partnership properties. If any such debt is assumed, then we will reduce the amount of net proceeds from this offering that would otherwise be paid to the Fund by the amount of such assumed debt, and we will use the net proceeds retained by us to repay in full at the closing any such assumed debt.

(g) Pro forma adjustment to reflect gross cash proceeds of approximately $300 million from the issuance and sale of 15,000,000 common units by QR Energy at an assumed initial public offering price of $20.00 per unit (the midpoint of the range shown on the cover of this prospectus).

(h) Pro forma adjustment to record the use of the net proceeds from the Offering, after deducting to repay $200 million in debt assumed per note (f) and to make a $300 million cash

F-9

distribution to the Fund. For further discussion on the application of the proceeds, please read “Use of Proceeds” on page 66.

(i) Pro forma adjustment to reflect estimated deferred financing costs of $3.0 million related to establishment of the new revolving credit facility, underwriting discount of $19.5 million and estimated offering expenses of $2.5 million.

Unaudited pro forma statements of operations adjustments

The Denbury Acquisition

(j) The “Denbury Acquisition Encore Assets” column represents the Revenues and Direct Operating Expenses related to the Denbury properties acquired by the Predecessor effective during May 2010. This activity includes the Encore Acquisition Corporation properties, as described below:


	•	The Denbury Acquisition Encore Assets column for the nine months ended September 30, 2010 includes the Revenues and Direct Operating Expenses of Encore Acquisition Corp (“Encore”), (including certain assets of Exco Resources, Inc. (“Exco”) assets, which were acquired by Encore August 11, 2009) for the period January 1, 2010 through May 14, 2010;

	•	The Denbury Acquisition Encore Assets column for the nine months ended September 30, 2009, includes the Revenues and Direct Operating Expenses of the Encore properties for the nine month period ended September 30, 2009 (exclusive of the Denbury Acquisition Exco Assets, which were not acquired by Encore until August 11, 2009); and

	•	The Denbury Acquisition Encore Assets column for the year ended December 31, 2009, includes the Revenues and Direct Operating Expenses of the Denbury Acquisition Encore Assets for the year ended December 31, 2009, including the Revenues and Direct Operating Expenses of the Denbury Acquisition Exco Assets for the period from August 12, 2009 through December 31, 2009.

(k) The “Denbury Acquisition Exco Assets” column represents the Revenues and Direct Operating Expenses related to the Denbury Acquisition Exco Assets, as described below:


	•	The Denbury Acquisition Exco Assets column for the nine months ended September 30, 2009, includes the Revenues and Direct Operating Expenses related to the Denbury Acquisition Exco Assets for the nine months ended September 30, 2009; and

	•	The Denbury Acquisition Exco Assets column for the year ended December 31, 2009, includes the Revenues and Direct Operating Expenses related to the Denbury Acquisition Exco Assets for the period from January 1, 2009 through August 11, 2009, the date they were sold to Encore.

(l) Pro forma adjustment to reflect additional depreciation, depletion and amortization of the Predecessor for the assets acquired by the Predecessor as part of the Denbury Acquisition, using the unit of production method under the full cost method of accounting, as if the Denbury Acquisition had occurred on January 1, 2009.

(m) Pro forma adjustment to reflect additional accretion of the discount on asset retirement obligations of the Predecessor as if the Denbury Acquisition had occurred on January 1, 2009.

(n) Pro forma adjustment to reflect the additional personnel of the Predecessor to manage the assets acquired as part of the Denbury Acquisition as if the Denbury Acquisition had occurred on January 1, 2009.

F-10

(o) Pro forma adjustment to reflect interest expense and the amortization of deferred financing fees on $548 million of borrowings by the Predecessor in connection with the Predecessor’s acquisition of the Denbury Acquisition assets. A one-eighth percentage point change in the interest rate would change pro forma interest expense by $0.51 million for the nine months ended September 30, 2010 and 2009, and $0.68 million for the year ended December 31, 2009.

The Contribution

(p) Pro forma adjustment to reflect the Revenues and Direct Operating Expenses associated with the oil and natural gas interests to be contributed to QR Energy by the Predecessor at the closing of the Offering. These adjustments are based on the actual results of the properties designated to be contributed to QR Energy. Historical lease operating statements by individual asset were used as the basis for the revenues and direct operating expenses.

(q) Pro forma adjustment to allocate the impairment of oil and natural gas properties attributable to the oil and natural gas interests to be contributed to QR Energy by the Predecessor at the closing of the Offering. The impairment allocation is based on the percentage of relative fair value of the Predecessor’s oil and natural gas interests (excluding any Denbury Acquisition assets) to be contributed to QR Energy by the Predecessor and those oil and natural gas interests that are to be retained by the Predecessor.

QR Energy estimates it would have incurred an additional impairment from full cost limitations of approximately $466 million for the year ended December 31, 2009 had the Denbury Acquisition occurred on January 1, 2009. The additional estimated impairment has not been reflected in the unaudited pro forma condensed statement of operations due to its non-recurring nature. In accordance with full cost accounting, full cost ceiling limitations are calculated using the 12-month average oil and natural gas prices for the most recent 12 months.

(r) Pro forma adjustment to reflect depreciation, depletion and amortization associated with oil and natural gas interests to be contributed to QR Energy by the Predecessor at the closing of the Offering. The calculation is based on the allocated cost of the oil and natural gas interests to be contributed to QR Energy by the Predecessor and the associated production and reserves as if the Contribution had occurred on January 1, 2009.

(s) Pro forma adjustment to reflect accretion of the discount on the asset retirement obligation attributable to the oil and natural gas interests to be contributed to QR Energy by the Predecessor as if the Contribution had occurred on January 1, 2009.

(t) Pro forma adjustment to allocate general and administrative expenses related to the oil and natural gas interests to be contributed to QR Energy by the Predecessor at the closing of the Offering. This adjustment is based on our Predecessor’s historical general and administrative expense, allocated based on a percentage of the relative fair value of the respective oil and natural gas interests to be contributed to QR Energy and the oil and natural gas interests to be retained by the Predecessor. This allocation includes the effect of relocation charges of $5.7 million that the Predecessor incurred in 2009, which were ascribed to the retained properties. Further, this adjustment is inclusive of a quarterly administrative services fee equal to 3.5% of Adjusted EBITDA which is estimated to be approximately $2.0 million, $1.9 million and $2.4 million on a pro forma basis for the nine months ended September 30, 2010, September 30, 2009 and the year ended December 31, 2009, respectively.

(u) Pro forma adjustment to allocate the historical realized and unrealized gain (losses) on derivative instruments contributed to QR Energy by the Predecessor at the closing of the Offering. The allocation was based on a percentage of the relative fair value of the Predecessor’s oil and natural gas interests to be contributed to QR Energy by the Predecessor and those oil and natural gas interests that are to be retained by the Predecessor.

F-11

The Offering

(v) Pro forma adjustment to reflect estimated incremental general and administrative expenses necessary for QR Energy to operate as a public company.

(w) Pro forma adjustment to reflect interest expense and the amortization of deferred financing fees on $225 million of borrowings by QR Energy under a new credit facility at LIBOR plus 2.5%, or 3.02%. A one-eighth percentage point change in the interest rate would change pro forma interest expense by $0.211 million for the nine months ended September 30, 2010 and 2009, and $0.282 million for the year ended December 31, 2009.


Note 3.	Pro Forma Net Income Per Limited Partner Unit

Pro forma net income per limited partner unit is determined by dividing the pro forma net income available to the common unitholders, after deducting the general partner’s 0.1% interest in pro forma net income, by the number of common units and subordinated units expected to be outstanding at the closing of the Offering. For purposes of this calculation, we assumed the aggregate number of common units was 28,547,737 and subordinated units was 7,145,866. All units were assumed to have been outstanding since January 1, 2009. Basic and diluted pro forma net income per unit are equivalent, as there will be no dilutive units at the date of the closing of the Offering of the common units of QR Energy.


Note 4.	Pro Forma Standardized Measure of Discounted Future Net Cash Flows

Supplemental reserve information (unaudited)

The following information summarizes the net estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof as of December 31, 2009 for the properties to be contributed to the Partnership at the closing of the Offering. The following historical reserve information of our predecessor is based upon reports of the independent reserve engineering firm of Miller & Lents, Ltd., while the pro forma reserves that support the pro forma adjustments were derived from internally generated reserve information. The estimates are prepared in accordance with SEC regulations.

Management believes the reserve estimates presented herein, prepared in accordance with the standards set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers, a copy of which is attached as Appendix 2 to the Miller and Lents report included in this prospectus in Appendix C, consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.

Decreases in the prices of oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our estimated proved reserves and our revenues, profitability and cash flow. As of December 31, 2009, based on evaluations prepared by our internal reserve engineers, the estimated proved reserves for the properties to be contributed to the Partnership at the closing of the Offering were

F-12

20,107.8 MBbls of oil, 56,330 MMcf of natural gas and 1,628.5 MBbls of NGLs, or 31,124.7 MBoe on a net equivalent basis.

Standardized Measure of Future Net Cash Flows (unaudited)

The standardized measure of future net cash flows relating to estimated proved crude oil and natural gas reserves is presented below (in thousands):


	December 31, 2009
													Predecessor
	Predecessor			Denbury			Pro Forma			Pro Forma			Retained			Pro Forma
	Historical			Acquisition			Adjustments(1)			Predecessor			Operations(2)			Partnership
Future cash inflows	$	707,028		$	1,746,352		$	634,236		$	3,087,616		$	1,687,249		$	1,400,367
Future production costs		(295,678	)		(739,022	)		(198,704	)		(1,233,404	)		(663,550	)		(569,854	)
Future development costs		(23,713	)		(64,968	)		(111,457	)		(200,138	)		(129,032	)		(71,106	)
Future income taxes		—			—			—			—			—			—

Future net cash flows		387,637			942,362			324,075			1,654,074			894,667			759,407
10% annual discount		(170,762	)		(456,130	)		(217,247	)		(844,139	)		(444,857	)		(399,282	)

Standardized measure of future net cash flows	$	216,875		$	486,232		$	106,828		$	809,935		$	449,810		$	360,125


(1)		Pro forma adjustments to reflect changes in estimates associated with the Denbury Acquisition reserve information. The Partnership’s management has prepared updated engineering estimates to include changes to timing and costs and its assessment as to what should be defined as a proved undeveloped reserve. Certain properties that were not classified as proved reserves by Denbury have now been classified as proved reserves in accordance with SEC guidelines by the Partnership’s management.

(2)		Pro forma adjustments to reflect the reserve information and the future cash flows associated with the properties to be retained by the Predecessor based on a specific identification method.

The standardized measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:


	•	An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

	•	In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our proved properties and the present value thereof are made using oil and gas sales prices, based on the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Our estimated net proved reserves as of December 31, 2009 were determined using $61.18 per barrel of oil and $3.87 per MMBtu of natural gas for our Predecessor and $61.18 per barrel of oil and $3.83 per MMBtu of natural gas for the Denbury Acquisition. 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.

	•	The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs.

	•	The reports reflect the pre-tax present value of estimated proved reserves to be $360.1 million at December 31, 2009. ASC 932 requires us to further reduce these estimates by an amount equal to the present value of estimated income taxes that may be payable by us in future years to arrive at the Standardized Measure of discounted future net cash flows. The Partnership is not subject to income tax; rather, the income or loss of the Partnership is included in the income tax returns of the partners.

F-13

Report of Independent Registered Public Accounting Firm

To the Partners of QR Energy, LP:

In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of QR Energy, LP at September 20, 2010 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of QR Energy, LP’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
September 29, 2010

F-14

QR ENERGY, LP

NOTE TO BALANCE SHEET

1. Organization and Operations

QR Energy, LP (the “Partnership”) is a Delaware limited partnership formed on September 20, 2010, to acquire certain of the assets of QA Holdings, LP, the predecessor entity. The Partnership intends to operate the acquired assets through a wholly owned operating company.

The Partnership intends to offer common units, representing limited partner interests, pursuant to a public offering. Separately, the Partnership will issue to Quantum Resource Funds common units and subordinated units, representing additional limited partner interests, and an aggregate 0.1% general partner interest to QRE GP, LLC. QRE GP, LLC will serve as the general partner of the Partnership.

QRE GP, LLC, as general partner, has committed to contribute $1 and Quantum Resource Funds, as the initial limited partners, have committed to contribute $999 in the aggregate to the Partnership as of September 20, 2010. These contributions receivable are reflected as a reduction to equity in accordance with generally accepted accounting principles. The accompanying financial statement reflects the financial position of the Partnership immediately subsequent to this initial capitalization. There have been no other transactions involving the Partnership as of September 20, 2010, or as of September 30, 2010 (unaudited).

F-16

QA HOLDINGS, LP

CONSOLIDATED BALANCE SHEETS

(In thousands)
(Unaudited)


	December 31,			September 30,
	2009			2010

ASSETS
Current assets:
Cash and cash equivalents	$	17,156		$	21,340
Accounts receivable:
Trade and other, net of allowance for doubtful accounts		2,796			4,013
Oil and gas sales		10,573			41,395
Due from affiliates		—			739
Derivative instruments		7,783			20,971
Prepaid and other current assets		2,533			2,430

Total current assets		40,841			90,888
Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting		709,552			1,670,933
Gas processing equipment		4,386			6,369
Furniture, equipment, and other		3,959			4,224

		717,897			1,681,526
Less accumulated depreciation, depletion, amortization and impairment		(592,254	)		(636,774	)

Total property and equipment, net		125,643			1,044,752

Other assets:
Investment in Ute Energy, LLC		41,597			47,151
Property reclamation deposit		10,729			10,730
Inventories		5,496			5,507
Derivative instruments		—			34,347
Deferred financing costs, net of amortization		925			10,869
Other long-term assets		1,539			1,549

Total other assets		60,286			110,153

Total assets	$	226,770		$	1,245,793

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	1,845		$	1,002
Oil and gas sales payable		8,578			6,560
Current portion of asset retirement obligations		2,250			1,676
Derivative instruments		14,484			24,304
Accrued and other liabilities		13,758			33,375

Total current liabilities		40,915			66,917
Other liabilities:
Long-term debt		86,450			547,668
Derivative instruments		52,998			67,474
Asset retirements obligations		32,994			62,052
Long term capital lease		101			63
Other long term liability		—			2,272

Total other liabilities		172,543			679,529
QA Holdings partners’ capital:
Partners’ capital		(1,421	)		16,795

Total QA Holdings partners’ capital		(1,421	)		16,795
Noncontrolling interest		14,733			482,552

Total equity		13,312			499,347

Total liabilities and equity	$	226,770		$	1,245,793

See accompanying notes to the unaudited consolidated financial statements.

F-17

QA HOLDINGS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2009			2010

Revenues:
Gas, oil, natural gas liquids, and sulfur sales	$	49,071		$	170,647
Processing and other		4,007			4,823

Total revenues		53,078			175,470

Operating Expenses:
Lease operating		23,724			52,152
Production taxes		4,975			12,528
Processing		2,293			2,985
Transportation		662			891
Impairment of oil and gas properties		28,338			—
Depreciation, depletion and amortization		13,743			45,149
Accretion of asset retirement obligations		2,847			2,648
Management fees		9,013			7,885
Acquisition evaluation costs		7			1,197
General and administrative		12,916			19,176
Other expense		—			224
Bargain purchase gain		(1,200	)		—

Total operating expenses		97,318			144,835

Income (loss) from operations		(44,240	)		30,635

Other income (expenses):
Equity in earnings of Ute Energy, LLC		1,603			1,490
Interest income		32			27
Dividends on investment in marketable equity securities		233			—
Realized losses on investment in marketable equity securities		(5,246	)		—
Unrealized gains on investment in marketable equity securities		5,640			—
Realized gains on commodity derivative contracts		42,177			5,132
Unrealized gains (losses) on commodity derivative contracts		(74,123	)		41,432
Gain on equity share issuance		—			4,064
Interest expense		(2,939	)		(31,392	)
Other income (expense)		10			(407	)

Total other income (expenses)		(32,613	)		20,346

Net Income (loss)		(76,853	)		50,981
Net Income (loss) attributable to noncontrolling interest		(72,649	)		45,817

Net Income (loss) attributable to controlling interest	$	(4,204	)	$	5,164

See accompanying notes to the unaudited consolidated financial statements.

F-18

QA HOLDINGS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)


	Nine Months Ended September 30,
	2009			2010

Cash flows from operating activities:
Net Income (loss)	$	(76,853	)	$	50,981
Adjustments to reconcile net income (loss) to net cash provided by
Operating activities:
Depreciation, depletion and amortization		13,743			45,149
Accretion of asset retirement obligations		2,847			2,648
Loss on disposal of furniture, fixtures and equipment		3			575
Amortization of deferred financing costs		461			2,042
Impairment of oil and gas properties		28,338			—
Amortization of costs of derivative contracts		911			—
Unrealized (gains) losses on commodity derivative contracts		71,511			(23,238	)
Unrealized gains on investment in marketable equity securities		(5,640	)		—
Realized losses on investment in marketable equity securities		5,246			—
Bargain purchase gain		(1,200	)		—
Equity in earnings of Ute Energy, LLC		(1,603	)		(1,490	)
Gain on equity share issuance		—			(4,064	)
Change in current assets and liabilities, net of acquisitions
(Increase) decrease in accounts receivable, net		12,973			(32,039	)
(Increase) decrease in due from affiliates		—			(739	)
(Increase) decrease in other current assets		2,319			102
(Increase) decrease in inventories		(447	)		(11	)
(Increase) decrease in other long term assets		—			(11	)
Increase (decrease) in accounts payable		(4,995	)		(843	)
Increase (decrease) in oil and gas sales payable		(1,358	)		(2,018	)
Increase (decrease) in accrued and other liabilities		(1,696	)		11,446
Increase (decrease) in other long term liabilities		—			2,272

Net cash provided by operating activities		44,560			50,762

Cash flows from investing activities:
Additions to oil and gas properties		(18,381	)		(33,653	)
Acquisition of oil and gas properties		(43,300	)		(895,922	)
Additions to furniture, equipment and other		(215	)		(1,468	)
Proceeds from sales of marketable equity securities		6,233			—
Increase in property reclamation deposit		(20	)		(1	)
Investment in Ute Energy, LLC		(1,925	)		—
Proceeds from sale of properties		16,287			—

Net cash used in investing activities		(41,321	)		(931,044	)

Cash flows from financing activities:
Contributions by partners and non-controlling interest owners		15,971			453,054
Distributions to partners and non-controlling interest owners		(21,199	)		(17,820	)
Proceeds from bank borrowings		33,000			574,752
Repayments on bank borrowings		(33,500	)		(113,534	)
Deferred financing costs		—			(11,986	)

Net cash provided by financing activities		(5,728	)		884,466

Increase (decrease) in cash and cash equivalents		(2,489	)		4,184
Cash and cash equivalents at beginning of year	$	21,035		$	17,156

Cash and cash equivalents at end of period	$	18,546		$	21,340

Supplemental disclosures of cash flow information:
Cash paid during the year for interest	$	2,055		$	8,666
Supplemental disclosures of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	(10,914	)	$	7,379
Insurance premium financed	$	—		$	118
Additions (reductions) to asset retirement obligations	$	(3,849	)	$	26,563

See accompanying notes to the unaudited consolidated financial statements.

F-20

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


(1)	Description of Business

QA Holdings, LP (QAH or the Partnership), a Delaware limited partnership, commenced operations on April 1, 2006 for the primary purpose of acquiring, owning, enhancing and producing oil and gas properties through its subsidiaries. QAH’s ownership interest in these subsidiaries ranges from 3% to 100%. QAH is deemed to have effective control of all of these subsidiaries and, therefore, the accounts of all of its subsidiaries are included in the accompanying consolidated financial statements. At September 30, 2010, the Partnership owns properties located in Alabama, Arkansas, Florida, Kansas, Louisiana, Mississippi, New Mexico, Oklahoma, and Texas.

QA Global GP, LLC (QA Global) is the general partner of and owns a 1% interest in QAH. The limited partners of QAH are QR Holdings, LP (QR), Aspect Asset Management, and members of management of QAH.

The following subsidiaries are wholly owned by QAH:


	•	Black Diamond Resources, LLC (Black Diamond)

	•	Black Diamond Resources 2, LLC

	•	Black Diamond GP, LLC

	•	QA GP, LLC (QA GP)

	•	Quantum Resources Management, LLC (QRM)

	•	QAB Carried WI, LP (QAB)

	•	QAC Carried WI, LP (QAC)

	•	QRFC, LP (QRFC)

	•	QR Ute Partners (QR Ute)

The following subsidiaries are not wholly owned but are deemed to be under QAH’s effective control with the ownership percentages listed below:


	General		Ownership			Limited		Ownership
	Partner		Percentage			Partners		Percentage

Quantum Resources A1, LP (QRA1)		QAP		3	%		Other		97	%
Quantum Resources B, LP (QRB)		QAP		3	%		Other		97	%
Quantum Resources C, LP (QRC)		QAP		3	%		Other		97	%
Quantum Aspect Partnership (QAP)		QA GP		1	%		Other		99	%

The entities listed above comprise Quantum Resources Fund I (the Fund). The Fund’s objective is to acquire and enhance mature, long-lived oil and gas producing assets. The Fund is managed by QA Asset Management, LLC (QAAM), an affiliated entity. Quantum Aspect Partnership (QAP) is the general partner of the investor limited partnerships (QRA1, QRB and QRC). QRA1, QRB, and QRC pay management fees to QAAM as specified in the respective partnership agreements. QAP receives, after the limited partners have recovered their initial investment and a preferred rate of return, participation in an additional 14% of cash flows generated by QRA1, QRB, and QRC.

Oil and gas properties are initially acquired by QAP or QRM and ownership interests are subsequently assigned to the entities in the Fund based on the relative contributed capital of each entity.

F-21

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Based on current relative capital contributions, ownership of properties acquired is allocated approximately as follows:


	Ownership
	Percentage

QRA1		93	%
QAB		2	%
QAC		3	%
Black Diamond		2	%

QAH and QA Global are managed by QAAM.

QRM provides personnel and services to QRA1, QRB, QRC, and Black Diamond. The prorata cost of these services is allocated to these entities based on their relative property ownership.

QRA1, QRB, and QRC (the LP’s) each have a 12-year term, which can be extended for two one-year periods. Under the partnership agreements, any funding of the partners’ equity commitments is to be completed within five years of the commencement date. The partnership agreements provide that the general partner and its affiliates contribute an amount equal to 3% of the LP’s contributions and purchase a 2% interest in each property in the name of Black Diamond. Black Diamond also receives an additional 2% carried interest from QRA1 in the properties acquired.

QRB provides funding to QAB, which then acquires a working interest in the properties. In exchange for the funding provided, QRB receives a net profits interest in those same properties.

QRC provides funding to QAC, which then acquires a working interest in the properties. In exchange for the funding provided, QRC receives a net profits interest in those same properties.

QRFC’s primary purpose is to raise funds through debt financing and subsequently invest those funds in QRC, an affiliated entity. QRFC’s investment is a preferred limited partnership interest that is senior to the other limited partnership interest. QRFC earns a return equal to the British Banker’s Association London Interbank Offered Rate (LIBOR) plus 2% per annum on its investment in QRC. All cash available to QRC shall first be paid to QRFC until an amount equal to any cumulative distributions due has been paid. As of September 30, 2010, QRFC has $16.6 million invested in QRC. As of September 30, 2010, QRFC had earned a return equal to approximately $838,000 and received distributions of approximately $710,000 on its investment in QRC. The remaining earned distribution of approximately $128,000 was paid in October 2010.

QRA1, QRB, and QRC have received subscriptions for limited partnership interests from their limited partners totaling approximately $1.2 billion as of September 30, 2010. QAP, the general partner of QRA1, QRB, and QRC, has made an equity commitment of $36.1 million, which represents 3% of the total equity commitments received. The partnership agreements provide that the general partner can request funding of equity commitments with a minimum 10 business days notice. As of September 30, 2010, the general and limited partners had funded $1.0 billion of their equity commitments. For the nine months ended September 30, 2010 and 2009, there were distributions paid to the partners of $17.8 million and $21.1 million, respectively.

The QRA1, QRB, and QRC partnership agreements provide that they will pay organization costs and costs paid to third parties for services in connection with obtaining funding commitments from the limited partners (placement agent fees). QRA1, QRB, and QRC combined are responsible for organization costs up to a limit of $1.5 million. Any costs in excess of this amount are paid by the partnerships; however, the management fees paid to QAAM are reduced by a corresponding amount.

F-22

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(2)	Summary of Significant Accounting Policies

The accounting policies followed by the Partnership are set forth in Note 2 of the audited consolidated financial statements for the year ended December 31, 2009, included elsewhere in this prospectus, and are supplemented by the notes to these consolidated financial statements. There have been no significant changes to these policies and it is suggested that these consolidated financial statements be read in conjunction with the audited consolidated financial statements and notes for the year ended December 31, 2009.

Basis of Presentation:

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2009 included elsewhere in this prospectus. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited interim consolidated financial statements reflect all adjustments that are, in the opinion management, necessary to present fairly the financial position as of, and the results of operations for, the periods presented.


*(a)*	*Property and Equipment*

The Partnership accounts for its oil and gas exploration and development activities under the full cost method of accounting. 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.

Pursuant to full cost accounting rules, the Partnership must perform a ceiling test at the end of each quarter related to its proved oil and gas properties. The ceiling test provides that capitalized costs less related accumulated depreciation, depletion and amortization may not exceed an amount equal to (1) the present value of future net revenue from estimated production of proved oil and gas reserves, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, discounted at 10% per annum; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any. If the net capitalized costs exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs.

For the ceiling test performed as of December 31, 2009, March 31, 2010, June 30, 2010 and September 30, 2010, the ceiling limitation calculation used a 12-month natural gas and oil price average, as adjusted for basis or location differentials using a beginning of month 12-month average, and held constant over the life of the reserves (“net wellhead prices”). For prior periods, the ceiling limitation calculation used natural gas and oil 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.

At December 31, 2009, March 31, 2010, June 30, 2010, and September 30, 2010 using the new rules (see Note 2) no write down was required. At March 31, 2009 using the old rules, a ceiling test impairment of $28.3 million was incurred. Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that an additional write-down could occur.

F-23

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The provision for depletion of proved oil and gas properties is calculated on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The provisions for depreciation of the gas processing plants classified outside of the full cost pool are calculated using the straight-line method over estimated useful lives of eight to twenty years. The provision for depreciation of the furniture and fixtures and computer hardware and software is calculated using the straight-line method over estimated useful lives of the assets ranging from three to five years.


*(b)*	*Contingencies*

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. A process is used to determine when expenses should be recorded for these contingencies and the estimate of reasonable amounts for the accrual. The Partnership closely monitors known and potential legal, environmental, and other contingencies and periodically determines when the Partnership should record losses for these items based on information available.

The Partnership is involved in various suits and claims arising in the normal course of business. QRM, and those QRM related entities owning record working interest in the Jay Field, brought suit against Santa Rosa County, protesting the County’s assessed value for the Jay interests. Santa Rosa County assessed the value of the Jay Field at approximately $90,000,000. At the assessment hearing prior to trial, QRM asserted that actual value of the Jay Field is zero. If the County were to prevail in its assessed value, the resulting tax to QRM will be approximately $1,300,000. QRM believes it has a sound case to prevail on an assessed value much lower than that asserted by Santa Rosa County.

In management’s opinion, the ultimate outcome of these items will not have a material adverse effect on the Partnership’s consolidated results of operations, financial position or cash flows. Based on management’s assessment, no contingent liabilities have been recorded as of December 31, 2009 and September 30, 2010.


*(c)*	*New Accounting Pronouncements*

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of consolidation guidance for Variable Interest Entities (VIEs). This Statement was codified in FASB ASC Topic 810, Consolidation. Topic 810 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amends certain guidance pertaining to the determination of the primary beneficiary when related parties are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. This statement was effective January 1, 2010 and its adoption did not impact our consolidated financial statements.

In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures About Fair Value Measurements,” which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010. The amendments to Level 3 disclosures were delayed until periods beginning after December 15, 2010 and are not anticipated to have a material impact on our financial statements upon adoption.

In February 2010, the FASB issued ASU 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements, which amends ASC 855 to address certain

F-24

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

implementation issues related to an entity’s requirement to perform and disclose subsequent-events procedures. All of the amendments in the Update are effective upon issuance of the final Update, except for conduit debt obligors, which is effective for interim and annual periods ending after June 15, 2010. Adoption of this Update did not have a material impact on our financial statements.


(3)	Acquisition and Divestiture of Assets


*(a)*	*Acquisition of Denbury Properties*

On May 14, 2010, the Partnership completed an acquisition certain oil and gas assets from Denbury Resources, Inc. for approximately $893 million. The assets are located in the Permian Basin, Mid Continent and East Texas. Total proved reserves of the acquired properties are estimated to be 77 Mmboe at May 14, 2010. The transaction was funded in cash from the proceeds of a combination of equity (cash calls to limited partners) and debt. The price is subject to a final settlement in the third quarter of 2010.

The acquisition qualifies as a business acquisition, and as such, the Partnership estimated the fair value of these properties as of the May 1, 2010 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. The Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 6 — Fair Value Measurements.

The Partnership estimated that as at June 30, 2010, the preliminary fair value of the Denbury net assets acquired was approximately $893 million, which the Partnership considered to be representative of the price paid by a typical market participant. This preliminary measurement resulted in a bargain purchase of $1 million recorded as part of operating expenses during the six-months ended June 30, 2010. During the third quarter of 2010 the Partnership updated their estimates of the fair value of these properties and associated liabilities. This resulted in a revision of assets from $904 million to $918 million and an increase in the Asset Retirement Obligation from $9.8 million to 24.9 million, and hence a reduction in the bargain purchase gain from $1 million recorded at June 30, 2010 to zero at September 30, 2010. This purchase price allocation remains preliminary and subject to change until the final closing statement is completed during the fourth quarter of 2010. The acquisition related costs related to the Denbury acquisition were approximately $1 million and are recorded as operating expenses for the nine months ended September 30, 2010.

The following table summarizes the consideration paid for the Denbury Properties and the updated fair value of the assets acquired and liabilities assumed as of May 1, 2010.


Consideration given to Denbury Resources, Inc. (in thousands):
Cash	$	888,785
Preferential rights - Additional properties not yet paid in September 2010		4,058

Total consideration	$	892,843

Recognized amounts of identifiable assets acquired and liabilities assumed:
Inventory of hydrocarbons	$	1,863
Proved developed properties		788,829
Proved undeveloped properties		84,000

F-25

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Unproved properties		43,000
Asset retirement obligations		(24,849	)

Total identifiable net assets	$	892,843

Summarized below are the consolidated results of operations for the nine months ended September 30, 2009 and 2010, on an unaudited pro forma basis, as if the acquisition had occurred on January 1 of each of the periods presented. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Partnership and the statement of revenues and direct operating expenses for the Denbury Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations.


	Nine Months Ended September 30,
	2009						2010
	Actual			Pro Forma			Actual		Pro Forma

Revenues	$	53,078		$	166,996		$	175,470	$	265,274
Net Income (Loss)	$	(76,853	)	$	(65,340	)	$	50,981	$	91,327


*(b)*	*Acquisition of Additional Land*

The Partnership signed and closed a purchase agreement on March 31, 2010 to acquire land within the Jay field from International Paper Company for $3.1 million.


*(c)*	*Acquisition of Shongaloo Properties*

On January 28, 2009, the Partnership completed an acquisition of 80 producing gas wells located in Arkansas and Louisiana for approximately $48.7 million. The acquisition was funded through cash calls to partners combined with borrowings under the Partnership’s credit facility. Total proved reserves of the acquired properties were estimated at 4.2 million barrels of oil equivalent at the date of acquisition.

The acquisition qualifies as a business combination, and as such, the Partnership estimated the fair value of these properties as of the January 28, 2009 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. In the estimation of fair value, the Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 6 — Fair Value Measurements.

The fair value of the Shongaloo Properties was approximately $51.6 million, which the Partnership considered to be representative of the price paid by a typical market participant. This measurement resulted in a bargain purchase of $1.2 million recorded as part of operating expenses during the six-months ended June 30, 2009 due to the increase in commodity prices as of the closing date of acquisition versus the commodity prices at the effective date. The acquisition related costs recognized as expense totaled $0.6 million and is recorded under operating expenses during the six-months ended June 30, 2009.

F-26

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the consideration paid for the Shongaloo Properties and the fair value of the assets acquired and liabilities assumed as of January 28, 2009.


Consideration given to El Paso E&P Company, L.P. (in thousands)
Cash	$	48,700
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	51,600
Asset retirement obligations		(1,700	)
Bargain Purchase		(1,200	)

Total identifiable new assets	$	48,700

Summarized below are the consolidated results of operations for the nine months ended September 30, 2009, on an unaudited pro forma basis, as if the acquisition had occurred on January 1, 2009. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Partnership and the statement of revenues and direct operating expenses for the Shongaloo Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations.


	Nine Months Ended September 30,
	2009
	Actual			Pro Forma

Revenues	$	53,078		$	54,075
Net Income (Loss)	$	(76,853	)	$	(76,070	)


(4)	Investments


*(a)*	*Investment in Ute Energy, LLC*

Ute Energy, LLC (Ute), a Delaware limited liability company, was formed on February 2, 2005 for the purpose of developing the mineral and surface estate of the Ute Indian Tribe by participating in oil and gas exploration and development, as well as the construction and operation of gas gathering and transportation facilities. Ute’s properties are located on the Uintah and Ouray Reservation in northeastern Utah. On July 9, 2007, QR Ute Partners (QR Ute) entered into an agreement to acquire up to 2,000,000 common units of Ute, representing 25% of the outstanding units of Ute, for $20.0 million, and up to 2,000,000 redeemable units of Ute for an additional $20.0 million. QR Ute is a Delaware general partnership owned by QRA1, QRB, QRC and Black Diamond in ownership percentages equal to the ratio of the respective capital contributions to partnerships to the total capital contributions to the Fund. QR Ute purchased 250,000 common units for $2.5 million and 250,000 redeemable units for $2.5 million at closing. During the years ended December 31, 2007 and 2008, QR Ute purchased an additional 1,750,000 common units and 1,750,000 redeemable units for $35.0 million, which fulfilled the funding commitment under the agreement. In April 2009, QR Ute purchased an additional 96,250 common units and 96,250 redeemable units for $1.9 million. During the nine months ended September 30, 2010, QR Ute was issued a further 231,307 redeemable units. As part of the wider recapitalization of Ute, QR Ute exchanged its 2,929,471 redeemable units for 2,929,471 common units and was issued an additional 175,126 redeemable units. This share-for-share exchange resulted in a gain of $4,064,000.

F-27

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The non-cash recapitalization converted certain of the redeemable units into Class A common units at a valuation of $10 per unit, with the remaining 175,126 redeemable units that will accrue a return equal to 12% per annum, being retained by QR Ute. The overall recapitalization resulted in a decrease in the common unit class ownership from 25% to approximately 24% attributable to the Partnership.

No impairment was recorded as of December 31, 2009 or September 30, 2010.

QAH accounts for its’ interest in UE using the equity method of accounting.


*(b)*	*Investment in Marketable Equity Securities*

The Partnership defines marketable securities as securities that can be readily converted into cash. Examples of marketable securities include U.S. government obligations, commercial paper, corporate notes and bonds, certificates of deposit and equity securities. Investments in marketable securities that are classified as trading are measured subsequently at fair value in the statement of financial position with the unrealized holding gains and losses reflected in earnings. Available-for-sale investments are initially recorded at cost and periodically adjusted to fair value and the changes are reflected in comprehensive income. Realized gains and losses and declines in value judged to be other than temporary are determined based on the specific identification method and are included in earnings. The Partnership determines the appropriate classification of securities at the time of purchase and reevaluates such classification as of each balance sheet date.

In 2008, the Partnership purchased $15.3 million of marketable equity securities. During the nine months ended September 30, 2009, the Partnership sold the remaining $11.5 million of the securities and recorded realized losses of $5.2 million, resulting in a change in the unrealized gain (loss) of $5.6 million. For the period since the original purchase, these securities have a cumulative $7.2 million realized loss. At December 31, 2009 and September 30, 2010, the Partnership did not own any marketable equity securities.


(5)	Long-Term Debt

In September 2006, the Partnership, through its subsidiaries QRA1, QRFC, and Black Diamond entered into three separate five-year revolving credit agreements with a syndicated bank group (the Credit Facilities). The combined Credit Facilities have a maximum commitment of $840 million and a current conforming borrowing base of $127.8 million at December 31, 2009.

The Credit Facilities for QRA1 and Black Diamond are held by mortgages on their oil and gas properties and related assets. QRFC’s credit facility is held by the oil and gas properties owned by QAC.

Borrowings under the Credit Facilities bear interest at the Alternative Base Rate (ABR) or the Eurodollar Rate plus a margin based on the borrowing base utilization. The ABR is defined as the higher of the prime rate or the sum of the Federal Funds Effective Rate plus 0.5%. The Eurodollar Rate is defined as the applicable British Bankers’ Association London Interbank Offered Rate (LIBOR) for deposits in U.S. dollars.

On May 14th, 2010 the Partnership terminated its existing credit facilities and, through its subsidiaries QRA1, QRFC, and Black Diamond, entered into three separate four-year revolving credit agreements with an expanded syndicated bank group (the New Credit Facilities). All outstanding loans under the previous credit facility were repaid in full from borrowings from the New Credit Facilities and all remaining unamortized loan costs totalling $668,000 were written off during the six-months ended June 30, 2010. The combined New Credit Facilities have a maximum commitment of $850 million and a current conforming borrowing base of $650 million. In conjunction with the amendments, the Partnership incurred $11.5 million of debt issuance costs which were capitalized and are being amortized

F-28

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

over the term of the respective amended agreements in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

As of September 30, 2010, the weighted interest rate was 3.02% on outstanding advances of $547.67 million, compared to 2.73% on outstanding advances of $86.45 million as of December 31, 2009.

The credit agreements contain financial and other covenants, including a current ratio test and a leverage test (Debt/EBITDAX). The Partnership is in compliance with all covenants at September 30, 2010.


(6)	Fair Value Measurements

The Partnership’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Partnership’s financial and non-financial assets and liabilities that are being measured on a recurring basis are measured and reported at fair value.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The statement establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:

Level 1 — Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 — Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.

Level 3 — Defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions for the asset or liability.

As required by the statement, the Partnership utilizes the most observable inputs available for the valuation technique utilized. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table sets

F-29

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

forth, by level within the hierarchy, the fair value of the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009 and September 30, 2010.


	Level 1		Level 2		Level 3			Total
	(In thousands)

December 31, 2009
Assets:
Commodity derivatives	$	—	$	—	$	7,783		$	7,783
Liabilities:
Commodity derivatives		—		—		(67,482	)		(67,482	)
September 30, 2010
Assets:
Commodity derivatives	$	—	$	—	$	55,318		$	55,318
Interest rate derivatives		—		—		—			—
Liabilities:
Commodity derivatives		—		—		(73,584	)		(73,584	)
Interest rate derivatives						(18,194	)		(18,194	)

All fair values reflected in the table above and on the consolidated balance sheets have been adjusted for non-performance risk. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 1 — Fair Value Measurements

As of December 31, 2009 and September 30, 2010, the Partnership did not have assets or liabilities measured under a Level 1 fair value hierarchy.

Level 2 — Fair Value Measurements

As of December 31, 2009 and September 30, 2010, the Partnership did not have assets or liabilities measured under a Level 2 fair value hierarchy.

Level 3 — Fair Value Measurements

Commodity Derivative Instruments — The fair value of the commodity derivative instruments are estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

Interest Rate Derivative Instruments — The fair value of the interest rate derivative instruments are estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

F-30

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2009 and 2010 (in thousands):


	Nine Months Ended September 30,
	2009			2010
Balance at beginning of period	$	—		$	(59,699	)
Total gains or losses (realized or unrealized):
Included in earnings		(32,297	)		25,563
Purchases, issuances and settlements		(40,125	)		(2,325	)
Transfers in and out of Level 3		49,684			—

Balance at end of the period		(22,738	)		(36,461	)

Changes in unrealized gains/(losses) relating to derivatives still held at end of period	$	(72,422	)	$	23,238


(7)	Derivatives


*(a)*	*Oil and Gas Commodity Hedges*

Oil and Gas Swaps

As of September 30, 2010, the Partnership held swap transactions contracts with three financial institutions, which are parties to its Credit Facilities, to manage its exposure to changes in the price of oil and natural gas related to the oil and gas properties. The derivative instruments are fixed for floating swap transactions. The following is a summary of the Partnership’s open derivative contracts as of September 30, 2010.


	Oil (WTI)
	Weighted
	Average
Term	$/Bbl		Bbls/d

2010	$	76.77		6,380
2011	$	76.02		5,521
2012	$	76.46		4,644
2013	$	75.43		4,591
2014	$	80.62		2,741
2015	$	87.40		2,000

WTI — West Texas Intermediate

$/Bbl — dollars per barrel

Bbls/d — barrels per day

F-31

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Natural Gas (NYMEX)
	Weighted
	Average
Term	$/Mmbtu		Mmbtu/d

2010	$	4.83		46,834
2011	$	5.66		42,660
2012	$	5.84		34,161
2013	$	6.06		30,765
2014	$	6.23		26,347
2015	$	5.52		6,100

NYMEX — New York Mercantile Exchange

$/Mmbtu — dollars per million British thermal units

Mmbtu/d — million British thermal units per day

Gas Basis Contracts

In February 2007, the Partnership also entered into certain financial instruments to effectively fix the basis differential on approximately 14,700 Mmbtu/d during the period from July 2007 through March 2010. There are four different delivery points where the Partnership markets a significant portion of its natural gas production associated to these contracts. In December 2008, the Partnership entered into additional gas basis differential contracts that were based on the Texas Gas Transmission Corp delivery point. The following is a summary of the natural gas swap prices, related basis swap prices, and resulting basis adjusted swap prices as of September 30, 2010.


			Texas Gas Transmission Corp.
								Basis
	NYMEX							Adjusted
Term	Swap Price		Mmbtu/d		Basis			Swap Price

2010	$	3.94		3,261	$	(0.17	)	$	3.77
2011	$	4.44		2,967	$	(0.16	)	$	4.28
2012	$	5.07		2,630	$	(0.16	)	$	4.91
2013	$	5.29		2,473	$	(0.15	)	$	5.14
2014	$	5.42		2,473	$	(0.15	)	$	5.27

Oil and Gas Collars

Also in November 2008, the Partnership entered into gas collars that were based on the NYMEX index. The collars are related to forecasted production from January 2010 through December 2010. In December 2008, the Partnership entered into additional oil and gas collars associated with the Shongaloo acquisition. The collars are related to forecasted production from January 2012 through December 2014.

In July 2010, the Partnership entered into an oil collar related to forecast production from January 2014 through December 2015. In September 2010, the Partnership entered into an offsetting oil collar to

F-32

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

reduce hedge volumes from January 2015 through December 2015 associated with the July 2010 oil collar and entered into a swap contract covering the amount of offset volumes. The following is a summary of the oil and gas collars as of September 30, 2010.


				Weighted		Weighted
				Average		Average
	Volume		Quantity	Floor		Ceiling			Contract
Collars	Per Day		Type	Pricing		Pricing		Index Price	Period

Oil		700	Bbls	$	70.00	$	110.00	NYMEX-WTI		1/1/2011 — 12/31/2012
Oil		70	Bbls	$	60.00	$	78.27	NYMEX-WTI		1/1/2012 — 12/31/2014
Oil		1,750	Bbls	$	70.00	$	108.25	NYMEX-WTI		1/1/2014 — 12/31/2015
Natural Gas		1,598	Mmbtu	$	7.00	$	8.90	NYMEX-Henry Hub		1/1/2010 — 12/31/2010
Natural Gas		2,518	Mmbtu	$	6.50	$	8.70	NYMEX-Henry Hub		1/1/2012 — 12/31/2014

The Partnership has elected not to designate the oil and gas commodity hedges as cash flow hedges under provisions of SFAS No. 133, as codified in ASC Topic 815. As a result, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value of the derivatives are recorded as gains or losses in the accompanying consolidated statements of operations. The table below summarizes the realized and unrealized gains and losses the Partnership incurred related to its oil and natural gas derivative instruments for the nine months ended September 30, 2009 and 2010.


	Nine Months Ended
	2009			2010
	(In thousands)

Realized gains (losses) on derivatives(1)	$	42,177		$	5,132
Unrealized gains (losses) on derivatives(1)		(74,123	)		41,432

Net realized and unrealized gains (losses) recorded	$	(31,946	)	$	46,564


(1)		Included as a separate component of other non-operating income (expense) in the consolidated statement of operations


*(b)*	*Interest Rate Derivative Contract*

During October 2007, the Partnership entered into a derivative instrument for a notional amount of $100.0 million to effectively fix the LIBOR component of the interest rate on its credit facility during the period from October 31, 2007 to October 31, 2009. Under the derivative instrument, the Partnership made payments to (or received payments from) the contract counterparty when the variable interest rate of the one-month LIBOR fell below or exceeded the fixed rate of 4.29%.

During June 2010, the Partnership entered into two tranches of derivative contracts with initial notional amounts of $275.0 million and $135.6 million to effectively fix the LIBOR component of the interest rate on its credit facility. Under the first tranche, the Partnership will make payments to (or receive payments from) the contract counterparties when the variable interest rate of the one-month LIBOR falls below or exceeds the fixed rate of 2.74% during the period from June 2010 to December 2016. In addition, the Partnership will make (or receive) payments from the contract counterparties when the one-month LIBOR falls below or exceeds the fixed rate of 1.95% during the period from July 2010 to December 2016 under the second tranche.

F-33

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The table below summarizes the realized and unrealized gains and losses the Partnership incurred related to its interest rate derivative instrument for the nine months ended September 30, 2009 and 2010.


	Nine Months
	Ended
	September 30,
	2009			2010
	(In thousands)

Realized gains (losses) on derivatives(1)	$	(2,963	)	$	(2,807	)
Unrealized gains (losses) on derivatives(1)		2,612			(18,194	)

Net realized and unrealized gains (losses) recorded	$	(351	)	$	(21,001	)


(1)		Included in “Interest expense” in the consolidated statement of operations

The following tables reflect the amounts that were recorded as derivative assets and liabilities on our Consolidated Balance Sheet at September 30, 2010 for our derivative instruments (in thousands):


	Fair Value of		Fair Value of
	Derivative		Derivative
	Assets(1)		Liabilities(2)

Derivative not designated as hedging instruments:
Commodity instruments	$	55,318	$	73,584
Interest Rate Instruments		—		18,194

Total derivatives not designated as hedging instruments	$	55,318	$	91,778


(1)		Included in derivative assets on our Consolidated Balance Sheet as of September 30, 2010.

(2)		Included in derivative liabilities on our Consolidated Balance Sheet as of September 30, 2010.

(8) Asset Retirement Obligations

The Partnership recorded a total of approximately $63.7 million as of September 30, 2010 for future asset retirement obligations in connection with the acquisition of the oil and gas properties. The following is a summary of the Partnership’s asset retirement obligations as of and for the nine months ended September 30, 2009 and 2010.


	Nine Months
	Ended
	2009			2010
	(In thousands)

Beginning of period	$	42,094		$	35,244
Assumed in acquisitions		1,731			24,849
Divested properties		(6,266	)		—
Revisions to previous estimates		686			1,714
Liabilities incurred		—			—
Liabilities settled		(1,595	)		(727	)
Accretion expense		2,847			2,648

End of period		39,497			63,728
Less: Current portion of asset retirement obligations		266			1,676

Asset retirement obligations — non-current	$	39,231		$	62,052

F-34

QA HOLDINGS, LP

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(9) Partners’ Equity

QA Global is the general partner of, and owns a 1% interest in, QAH. The limited partners of QAH are QR and Aspect Asset Management, and members of management of QAH. The earnings of the Partnership are allocated to the partners based on their respective ownership percentages.


(10)	Employee Benefit Plans

The Partnership has a 401(k) savings plan available to all eligible employees. For the nine months ended September 30 2009, the Partnership matched 100% of employee contributions up to 6% of the employee’s salary, whereas for the nine months ended September 30, 2010, the Partnership matched 100% of employee contributions up to 3% of the employee’s salary. Matching contributions vest immediately. The Partnership made matching cash contributions to the plan for the nine months ended September 30, 2009 and 2010 of approximately $473,000 and $259,000 respectively.


(11)	Related-Party Transactions

QRA1, QRB, and QRC have management agreements with QAAM, an affiliated entity, to provide management services for the operation and supervision of the partnerships. The management fee is determined by a formula based on the partners’ invested capital or the equity capital commitment. During the nine months ended September 30, 2009 and 2010, the partnerships paid $9.0 million and $9.0 million, respectively, to QAAM for management fees. During the nine months ended September 30, 2010, the Partnership determined that it had overpaid QAAM by a total of $1.0 million, spread ratably over the last four years since inception in 2006. Accordingly, this amount will be repaid in due course against future management fees and the management fee disclosed in operating expenses has been reduced by $1.0 million during the nine months ended September 30, 2010.

QAH has obtained services from an affiliated entity related to its normal business operations. The amounts paid for these services were insignificant for the nine months ended September 30, 2009 and 2010.


(12)	Commitments


*(a)*	*Property Reclamation Deposit*

In connection with the 2006 Gulf Coast acquisition between ExxonMobil Corporation and QRM, the Partnership was required to deposit $10 million into an escrow account as security for abandonment and remediation obligations. As of December 31, 2009 and September 30, 2010, $10.7 million was recorded in other assets related to the deposit. In addition to the cash deposit, the Partnership was required to provide a $3 million letter of credit. The agreement requires an additional $3 million letter of credit to be issued in favor of the seller each year through 2012. Letters of credit totaling $12.0 million had been issued as of December 31, 2009 and September 30, 2010. The Partnership is required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to the Partnership until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, the Partnership has the right to request a refund of a portion or all of the property reclamation deposit. Granting of the request is at the seller’s sole discretion.


(13)	Subsequent Events

On November 19, 2010, QA Holdings, LP entered into a purchase and sale agreement to acquire certain oil and gas assets in the Permian Basin for $80 million from a third party. These assets are currently producing approximately 800 barrels of oil equivalent per day from waterflood oil fields that

F-35

Report of Independent Registered Public Accounting Firm

To the Members of

QA Global GP, LLC:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, of changes in partner’s capital and of cash flows present fairly, in all material respects, the financial position of QA Holdings, LP and its subsidiaries (the “Partnership”) at December 31, 2009, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, effective December 31, 2009, the Partnership has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

April 30, 2010

except for Note 2(0) for which the date is November 3, 2010

F-37

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

QA Global GP, LLC:

We have audited the accompanying consolidated balance sheet of QA Holdings, LP (the Partnership) as of December 31, 2008, and the related consolidated statements of operations, changes in partners’ capital and cash flows for each of the years in the two-year period ended December 31, 2008. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of QA Holdings, LP as of December 31, 2008, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2008 in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Denver, Colorado

April 30, 2009

F-38

QA HOLDINGS, LP

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31,			December 31,
	2008			2009

ASSETS
Current assets:
Cash and cash equivalents	$	21,035		$	17,156
Accounts receivable:
Trade and other, net of allowance for doubtful accounts		9,832			2,796
Oil and gas sales		15,944			10,573
Derivative instruments		47,038			7,783
Prepaid and other current assets		8,948			2,533

Total current assets		102,797			40,841

Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting		677,228			709,552
Gas processing equipment		4,295			4,386
Furniture, equipment, and other		3,820			3,959

		685,343			717,897
Less accumulated depreciation, depletion, amortization and impairment		(547,517	)		(592,254	)

Total property and equipment, net		137,826			125,643

Other assets:
Investment in Ute Energy, LLC		36,997			41,597
Property reclamation deposit		10,710			10,729
Investment in marketable equity securities		5,839			—
Inventories		5,026			5,496
Derivative instruments		2,646			—
Deferred financing costs, net of amortization		1,552			925
Other long-term assets		1,544			1,539

Total other assets		64,314			60,286

Total assets	$	304,937		$	226,770


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	6,600		$	1,845
Oil and gas sales payable		7,876			8,578
Current portion of asset retirement obligations		1,500			2,250
Derivative instruments		—			14,484
Accrued and other liabilities		19,682			13,758

Total current liabilities		35,658			40,915
Long-term debt		88,750			86,450
Derivative instruments		—			52,998
Asset retirements obligations		40,594			32,994
Long term capital lease		—			101
Commitments and Contingencies (see Note 12)

QA Holdings partners’ capital:
Partners’ capital		5,957			(1,421	)

Total QA Holdings partners’ capital		5,957			(1,421	)

Noncontrolling interest		133,978			14,733

Total equity		139,935			13,312

Total liabilities and equity	$	304,937		$	226,770

See accompanying notes to the consolidated financial statements.

F-39

QA HOLDINGS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)


	Year Ended December 31,
	2007			2008			2009

Revenues:
Gas, oil, natural gas liquids, and sulfur sales	$	164,628		$	248,529		$	69,193
Processing		6,649			18,741			3,608
Resale of natural gas		—			13,741			—
Other		40			59			—

Total revenues		171,317			281,070			72,801

Operating expenses:
Lease operating		77,767			90,424			33,328
Purchases of natural gas		—			13,960			—
Production taxes		12,954			14,566			7,587
Processing		4,339			11,906			3,045
Transportation		389			323			881
Impairment of oil and gas properties		—			451,440			28,338
Depreciation, depletion and amortization		42,889			49,309			16,993
Accretion of asset retirement obligations		2,751			3,004			3,585
Management fees		11,482			12,018			12,018
Acquisition evaluation costs		895			216			582
Organizational costs		207			—			—
General and administrative		19,575			14,636			18,879
Bargain purchase gain		—			—			(1,200	)

Total operating expenses		173,248			661,802			124,036

Loss from operations		(1,931	)		(380,732	)		(51,235	)

Other income (expenses):
Equity in earnings of Ute Energy, LLC		7			(3,010	)		2,675
Interest income		978			617			37
Dividends on investment in marketable equity securities		—			579			233
Realized losses on investment in marketable equity securities		—			(1,968	)		(5,246	)
Unrealized gains (losses) on investment in marketable equity securities		—			(5,640	)		5,640
Realized gains (losses) on commodity derivative contracts		6,861			(34,666	)		47,993
Unrealized gains (losses) on commodity derivative contracts		(157,250	)		169,321			(111,113	)
Interest expense		(17,359	)		(13,034	)		(3,753	)
Other expense		—			—			(645	)

Total other expenses		(166,763	)		112,199			(64,179	)

Net loss		(168,694	)		(268,533	)		(115,414	)
Net loss attributable to noncontrolling interest		(159,937	)		(258,541	)		(107,528	)

Net loss attributable to controlling interest	$	(8,757	)	$	(9,992	)	$	(7,886	)

See accompanying notes to the consolidated financial statements.

F-40

QA HOLDINGS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)


	General			Limited			Total QA Holdings			Noncontrolling
	partner			partners			partners’ capital			Interest			Total Equity

Balances — December 31, 2006	$	112		$	11,150		$	11,262		$	308,337		$	319,599
Contributions by partners		26			2,572			2,598			86,801			89,399
Net loss		(88	)		(8,669	)		(8,757	)		(159,937	)		(168,694	)

Balances — December 31, 2007	$	50		$	5,053		$	5,103		$	235,201		$	240,304
Contributions by partners		114			11,272			11,386			175,346			186,732
Distributions to partners		(5	)		(535	)		(540	)		(18,028	)		(18,568	)
Net loss		(100	)		(9,892	)		(9,992	)		(258,541	)		(268,533	)

Balances — December 31, 2008		59			5,898			5,957			133,978			139,935
Contributions by partners		14			1,427			1,441			14,550			15,991
Distributions to partners		(9	)		(924	)		(933	)		(26,267	)		(27,200	)
Net loss		(79	)		(7,807	)		(7,886	)		(107,528	)		(115,414	)

Balances — December 31, 2009	$	(15	)	$	(1,406	)	$	(1,421	)	$	14,733		$	13,312

See accompanying notes to the consolidated financial statements.

F-41

QA HOLDINGS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2007			2008			2009
	(In thousands)

Cash flows from operating activities:
Net loss	$	(168,694	)	$	(268,533	)	$	(115,414	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		42,889			49,309			16,993
Accretion of asset retirement obligations		2,752			3,004			3,585
Loss on disposal of furniture, fixtures and equipment		—			—			723
Amortization of deferred financing costs		521			556			627
Impairment of oil and gas properties		—			451,440			28,338
Purchase of derivative contracts		(7,546	)		(2,694	)		—
Amortization of costs of derivative contracts		—			7,981			1,219
Unrealized (gains) losses on commodity derivative contracts		158,267			(167,389	)		108,164
Unrealized (gains) losses on investment in marketable equity securities		—			5,640			(5,640	)
Realized losses on investment in marketable equity securities		—			1,968			5,246
Bargain purchase gain		—			—			(1,200	)
Equity in earnings of Ute Energy, LLC		(7	)		3,010			(2,675	)
Change in current assets and liabilities, net of acquisitions:
(Increase) decrease in accounts receivable, net		(17,075	)		3,351			12,407
(Increase) decrease in other current assets		(1,517	)		(2,911	)		3,109
(Increase) decrease in inventories		—			(4,208	)		(470	)
(Increase) decrease in other long term assets		—			—			6
Increase (decrease) in accounts payable		(1,376	)		2,550			(4,755	)
Increase (decrease) in oil and gas sales payable		2,167			5,142			702
Increase (decrease) in accrued and other liabilities		14,458			(12,934	)		13,942

Net cash provided by operating activities		24,839			75,282			64,907

Cash flows from investing activities:
Additions to oil and gas properties		(38,631	)		(90,125	)		(31,278	)
Acquisition of oil and gas properties		(17,331	)		(391	)		(43,300	)
Additions to furniture, equipment and other		(2,002	)		(943	)		(1,456	)
Increase in property reclamation deposit		(445	)		(254	)		(19	)
Investment in Ute Energy, LLC		(13,000	)		(27,000	)		(1,925	)
Investment in marketable equity securities		—			(15,291	)		—
Proceeds from sales of marketable equity securities		—			1,843			6,233
Increase in other assets		(1,544	)		(5,000	)		—
Proceeds from sale of properties					—			16,287

Net cash used in investing activities		(72,953	)		(137,161	)		(55,458	)

Cash flows from financing activities:
Contributions by partners and minority interest owners		88,516			186,731			15,991
Distributions to partners and minority interest owners		—			(18,568	)		(27,019	)
Proceeds from bank borrowings		28,400			25,000			33,000
Repayments on bank borrowings		(26,625	)		(162,525	)		(35,300	)
Deferred financing costs		(401	)		(398	)		—

Net cash provided by (used in) financing activities		89,890			30,240			(13,328	)

Increase (Decrease) in cash and cash equivalents		41,776			(31,639	)		(3,879	)
Cash and cash equivalents at beginning of year	$	10,898		$	52,674		$	21,035

Cash and cash equivalents at end of period	$	52,674		$	21,035		$	17,156

Supplemental disclosures of cash flow information:
Cash paid during the year for interest	$	16,536		$	9,000		$	2,480
Supplemental disclosures of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	7,150		$	3,828		$	(11,206	)
Insurance premium financed	$	—		$	—		$	1,695
Additions (reductions) to asset retirement obligations	$	1,100		$	1,370		$	(10,435	)
Contributions receivable from partners	$	882		$	—		$	—

See accompanying notes to the consolidated financial statements.

F-42

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)	Description of Business

QA Holdings, LP (QAH or the Partnership), a Delaware limited partnership, commenced operations on April 1, 2006 for the primary purpose of acquiring, owning, enhancing and producing oil and gas properties through its subsidiaries. QAH’s ownership interest in these subsidiaries ranges from 3% to 100%. QAH is deemed to have effective control of all of these subsidiaries and, therefore, the accounts of all of its subsidiaries are included in the accompanying consolidated financial statements. At December 31, 2009, the Partnership owns properties located in Alabama, Arkansas, Florida, Louisiana, Mississippi, New Mexico, Oklahoma, and Texas.

QA Global GP, LLC (QA Global) is the general partner of and owns a 1% interest in QAH. The limited partners of QAH are QR Holdings, LP (QR), Aspect Asset Management, and members of management of QAH.

The following subsidiaries are wholly owned by QAH:


	•	Black Diamond Resources, LLC (Black Diamond)

	•	Black Diamond Resources 2, LLC

	•	Black Diamond GP, LLC

	•	QA GP, LLC (QA GP)

	•	Quantum Resources Management, LLC (QRM)

	•	QAB Carried WI, LP (QAB)

	•	QAC Carried WI, LP (QAC)

	•	QRFC, LP (QRFC)

	•	QR Ute Partners (QR Ute)

The following subsidiaries are not wholly owned but are deemed to be under QAH’s effective control with the ownership percentages listed below:


	General	Ownership			Limited		Ownership
	Partner	Percentage			Partners		Percentage

Quantum Resources A1, LP (QRA1)	QAP		3	%		Other		97	%
Quantum Resources B, LP (QRB)	QAP		3	%		Other		97	%
Quantum Resources C, LP (QRC)	QAP		3	%		Other		97	%
Quantum Aspect Partnership (QAP)	QA GP		1	%		Other		99	%

Oil and gas properties are initially acquired by QAP or QRM and ownership interests are subsequently assigned to the entities in the Fund based on the relative contributed capital of each entity.

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Based on current relative capital contributions, ownership of properties acquired is allocated approximately as follows:


	Ownership Percentage

QRA1		93	%
QAB		2	%
QAC		3	%
Black Diamond		2	%

QAH and QA Global are managed by QAAM.

QRM provides personnel and services to QRA1, QRB, QRC, and Black Diamond. The prorata cost of these services is allocated to these entities based on their relative property ownership.

QRB provides funding to QAB, which then acquires a working interest in the properties. In exchange for the funding provided, QRB receives a net profits interest in those same properties.

QRC provides funding to QAC, which then acquires a working interest in the properties. In exchange for the funding provided, QRC receives a net profits interest in those same properties.

QRFC’s primary purpose is to raise funds through debt financing and subsequently invest those funds in QRC, an affiliated entity. QRFC’s investment is a preferred limited partnership interest that is senior to the other limited partnership interest. QRFC earns a return equal to the British Banker’s Association London Interbank Offered Rate (LIBOR) plus 2% per annum on its investment in QRC. All cash available to QRC shall first be paid to QRFC until an amount equal to any cumulative distributions due has been paid. As of December 31, 2009, QRFC has $2.8 million invested in QRC. As of December 31, 2009, QRFC had earned a return equal to approximately $682,000 and received distributions of approximately $666,000 on its investment in QRC. The remaining earned distribution of approximately $16,000 was paid in March 2010.

QRA1, QRB, and QRC have received subscriptions for limited partnership interests from their limited partners totaling approximately $1.2 billion as of December 31, 2009. QAP, the general partner of QRA1, QRB, and QRC, has made an equity commitment of $36.1 million, which represents 3% of the total equity commitments received. The partnership agreements provide that the general partner can request funding of equity commitments with a minimum 10 business days notice. As of December 31, 2009, the general and limited partners had funded $577.4 million of their equity commitments. For the years ended December 31, 2008 and 2009, there were distributions paid to the partners of $18.6 million and $27.2 million, respectively.

F-44

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(2)	Summary of Significant Accounting Policies


*(a)*	*Principles of Consolidation*

The accompanying consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.


*(b)*	*Use of Estimates*

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Depreciation, depletion and amortization of oil and gas properties and the impairment of oil and gas properties are determined using estimates of oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including future costs to dismantle, dispose, and restore the Partnership’s properties. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way.


*(c)*	*Basis of Presentation*

The accompanying financial statements have been prepared on an accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America. Certain prior period amounts have be reclassified to conform to the current year presentation.

F-45

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Partnership has reclassified its presentation of the 2007 and 2008 realized and unrealized gains and losses on commodity derivative contracts from revenue to other income (expenses) in the statement of operations to conform to the presentation of 2009, as summarized below.


	2007						2008
	As Previously						As Previously
	Presented			As Reclassified			Presented			As Reclassified

Revenues:
Gas, oil, natural gas liquids, and sulfur sales	$	164,628		$	164,628		$	248,529		$	248,529
Realized gains (losses) on derivative instruments		6,861			—			(34,666	)		—
Unrealized gains (losses) on derivative instruments		(157,250	)		—			169,321			—
Processing		6,649			6,649			18,741			18,741
Resale of natural gas		—			—			13,741			13,741
Other		40			40			59			59

Total revenues		20,928			171,317			415,725			281,070

Other income (expenses):
Equity in earnings of Ute Energy, LLC		7			7			(3,010	)		(3,010	)
Interest income		978			978			617			617
Dividends on investment in marketable equity securities		—			—			579			579
Realized losses on investment in marketable equity securities		—			—			(1,968	)		(1,968	)
Unrealized gains (losses) on investment in marketable equity securities		—			—			(5,640	)		(5,640	)
Realized gains (losses) on derivative instruments		—			6,861			—			(34,666	)
Unrealized gains (losses) on derivative instruments		—			(157,250	)		—			169,321
Interest expense		(17,359	)		(17,359	)		(13,034	)		(13,034	)
Other income		—			—			—			—

Total other expenses		(16,374	)		(166,763	)		(22,456	)		112,199

Net loss	$	(8,757	)	$	(8,757	)	$	(9,992	)	$	(9,992	)


*(d)*	*Cash and Cash Equivalents*

The Partnership considers all highly liquid instruments purchased with a maturity when acquired of three months or less to be cash equivalents. The Partnership continually monitors its positions with, and the credit quality of, the financial institutions it invests with.

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


*(e)*	*Trade Accounts Receivable*

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Partnership uses the specific identification method of providing allowances for doubtful accounts. At December 31, 2008 and 2009, the allowance for doubtful accounts was not material.


*(f)*	*Inventories*

Inventories, consisting primarily of tubular goods and other well equipment held for use in the development and production of natural gas and crude oil reserves, are carried at the lower of cost or market, on a first-in, first-out basis. Adjustments are made from time to time to recognize, as appropriate, any reductions in value. For the year ended December 31, 2008, the Partnership recognized a $1.7 million inventory write-down, which was recognized in the consolidated statement of operations as a component of impairment of oil and gas properties. Based on management’s assessment, no reduction in value was needed as of December 31, 2009.


*(g)*	*Revenue Recognition*

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers. Under this method of revenue recognition, a gas imbalance is created if the quantity sold is greater than or less than the Partnership’s entitlement share in any particular period. To the extent there are sufficient quantities of natural gas remaining to make up the gas imbalance, oil and gas reserves are adjusted to reflect the overproduced or underproduced position. In situations where there are insufficient reserves available to make up an overproduced imbalance, a liability is established. At December 31, 2008 and 2009, natural gas imbalances were not material.


*(h)*	*Income Taxes*

QAH is treated as a partnership for income tax purposes. Generally, all taxable income and losses of the Partnership are reported on the income tax returns of the partners, and therefore, no provision for income taxes has been recorded in the Partnership’s accompanying consolidated financial statements. The Partnership is subject to the Texas and Delaware franchise taxes, however, such amounts are not significant.


*(i)*	*Property and Equipment*

Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. To the extent that the evaluation indicates these properties are impaired, the amount of impairment assessed is added to the capitalized costs to be amortized.

F-47

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For periods prior to December 31, 2009, the ceiling limitation calculation used natural gas and oil 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. At December 31, 2009, the ceiling limitation calculation used a 12-month natural gas and oil price average, as adjusted for basis or location differentials using a beginning of month 12-month average, and held constant over the life of the reserves.

Due to continued declines in gas prices at both December 31, 2008 and March 31, 2009, capitalized costs of our proved oil and gas properties exceeded our ceiling, resulting in non-cash write-downs of $449.7 million and $28.3 million, respectively. At December 31, 2008 and March 31, 2009, the ceiling test value of the Partnership’s oil reserves was calculated based on the quarters’ end West Texas Intermediate posted price of $41.00 per barrel and $48.39 per barrel, respectively, adjusted by lease for quality, transportation fees, and regional price differentials, and for natural gas reserves was based on the December 31, 2008 and March 31, 2009 Henry Hub spot market price of $5.71 per million British thermal unit (MMbtu) and $3.58 MMbtu, respectively, adjusted by lease for energy content, transportation fees, and regional price differentials.

At December 31, 2009, using the new rules (see Note 2) no write down was required. Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that an additional write-down could occur.

Gain or loss is not recognized on the sale of oil and gas properties unless the sale significantly alters the amortization base. Expenditures for maintenance and repairs are charged to expense in the period incurred.


*(j)*	*Deferred Financing Costs*

Costs incurred in connection with the execution or modification of the Partnership’s credit facilities and secured hedge agreements are capitalized and amortized on a straight-line basis over the period of the revolver.


*(k)*	*Asset Retirement Obligations*

The Partnership follows the guidance in ASC Topic 410, Asset Retirement and Environmental Obligations (formerly SFAS No. 143, Accounting for Asset Retirement Obligations) in accounting for asset

F-48

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

retirement obligations (ARO). This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC Topic 410 requires entities to record the fair value of a liability for an ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Oil and gas producing companies incur this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depleted as a component of the full cost pool. Upon settlement of the liability, an entity reports a gain or loss to the extent the actual costs differ from the recorded liability.


*(l)*	*Derivatives*

A majority of the Partnership’s revenues are based on the price of oil and gas. To manage its exposure to oil and gas price volatility, the Partnership enters into commodity derivative instruments. Commodity derivative instruments may take the form of futures contracts, swaps, or options. The Partnership is also exposed to changes in interest rates, primarily as a result of variable rate borrowings under the credit facility. In an effort to reduce this exposure, the Partnership has, from time to time, entered into derivative contracts (interest rate swaps) to mitigate the risk of interest rate fluctuations. For commodity derivatives, both realized and unrealized gains and losses are recorded as separate components of other income (expense). For interest rate derivatives, both realized and unrealized gains and losses are recorded as a component of interest expense in the consolidated statement of operations.

The Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as codified in ASC Topic 815, Derivatives and Hedging, requires recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. Realized gains and losses on derivative hedging instruments are recorded currently in earnings. Unrealized gains and losses on derivatives are also recorded currently in earnings unless the derivatives qualify and are appropriately designated as hedges. Unrealized gains or losses on derivative instruments that qualify and are designated as hedges are deferred in other comprehensive income until the related transaction occurs. The Partnership has not designated any of its derivative instruments as hedges. As a result, the Partnership marks its derivative instruments to fair value in accordance with the provisions of ASC Topic 815 and recognizes the changes in fair market value in earnings. Also see Note 6 — Fair Value Measurements and Note 7 — Derivatives for additional discussion.

Derivative financial instruments are generally executed with major financial institutions that expose the Partnership to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. All of the Partnership’s derivatives at December 31, 2009 are with parties that are also lenders under the Partnership’s credit facility. The credit worthiness of the counterparties is subject to continual review. The Partnership believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Partnership has no past-due receivables from its counterparties. The Partnership’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.


*(m)*	*Contingencies*

F-49

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In management’s opinion, the ultimate outcome of these items will not have a material adverse effect on the Partnership’s consolidated results of operations or financial position. Based on management’s assessment, no contingent liabilities have been recorded as of December 31, 2008 and 2009.


*(n)*	*Concentrations of Credit and Market Risk*

Credit risk — Financial instruments which potentially subject the Partnership to credit risk consist principally of temporary cash balances, investments in marketable securities, accounts receivable from affiliates and derivative financial instruments. The Partnership maintains cash and cash equivalents in bank deposit accounts which, at time, may exceed the federally insured limits. The Partnership has not experienced any significant losses from such investments. The Partnership attempts to limit the amount of credit exposure to any one financial institution or company. Procedures that may be used to manage credit exposure include credit approvals, credit limits and terms, letters of credit, prepayments and rights of offset. The Partnership’s investments in marketable securities are managed within guidelines established by management. The Partnership’s customer base consists primarily of major integrated and international oil and gas companies, as well as smaller processors and gatherers. The Partnership believes the credit quality of its customers is high.

Market Risk — The Partnership’s activities primarily consist of acquiring, owning, enhancing and producing oil and gas properties. The future results of the Partnership’s operations, cash flows and financial condition may be affected by changes in the market price of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Partnership, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment and, other regional and political events, none of which can be predicted with certainty.


*(o)*	*Revision of Statement of Cash Flows*

The Partnership determined that “Proceeds from sales of marketable equity securities” in the amount of $6,233,000, as previously presented within cash flows from operating activities, should have been presented within cash flows from investing activities for the year ended December 31, 2009. The Partnership evaluated the impact of this adjustment under the guidance in ASC 250-10 (SEC Staff Accounting Bulletin No. 99, “Materiality”) and concluded that this item was not material to the statement of cash flows for such period. The Partnership has, however, chosen to revise its statement of cash flows to reclassify $6,233,000 from cash flows from operating activities to cash flows from investing activities.


*(p)*	*New Accounting Pronouncements*

In June 2009, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 168, The FASB Accounting Standards Codification (ASC) and the Hierarchy of Generally Accepted Accounting Principle, as codified in FASB ASC Topic 105, Generally Accepted Accounting Principles. This statement establishes only two levels of U.S. GAAP, authoritative and

F-50

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

nonauthoritative. The FASB ASC became the authoritative, nongovernmental GAAP, except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification became nonauthoritative. This statement is effective for financial statements for interim or annual reporting periods ending after September 15, 2009 and was effective for the Partnership. Therefore, all accounting references have been updated, and SFAS references have been replaced with ASC references. As the ASC was not intended to change or alter existing GAAP, it did not have any impact on the Partnership’s consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157), as codified in ASC Topic 820, Fair Value Measurements and Disclosures. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements regarding fair value measurement. As of January 1, 2009, the Partnership fully adopted this statement, requiring fair value measurements of nonfinancial assets and nonfinancial liabilities. The adoption of this statement did not materially impact the Partnership’s consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (Revised), Business Combinations (SFAS No. 141R), as codified in ASC Topic 805, Business Combinations. This statement requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified by the statement. This includes the measurement of the acquirer’s shares issued in consideration for a business combination, the recognition of contingent considerations, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. This statement applies prospectively and was effective for the Partnership beginning January 1, 2009. The adoption of this statement did not materially impact the Partnership’s consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, as codified in ASC Topic 810, Consolidation. This statement amends Accounting Research Bulletins (ARB) No. 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This standard clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, This standard requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Effective January 1, 2009, the Partnership implemented the new guidance which resulted in changes to the presentation for noncontrolling interests. This implementation did not have a material impact on the Partnership’s financial position or results of operations. All historical periods presented in the accompanying consolidated financial statements reflect these changes to the presentation for noncontrolling interests.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS No. 161), as codified in ASC Topic 815, Derivatives and Hedging. This statement is intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their financial position, performance and cash flows. It seeks to achieve these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It

F-51

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

also seeks to improve the transparency of the location and amounts of derivative instruments in the Partnership’s consolidated financial statements and how they are accounted for. This statement was effective for the Partnership beginning January 1, 2009.

On December 31, 2008, the Securities and Exchange Commission (“SEC”) issued, “Modernization of Oil and Gas Reporting” (“Final Rule”). The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports for years ending on or after December 31, 2009.

On January 6, 2010, the FASB issued Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosures (ASU 2010-03), which aligns the FASB’s oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s Final Rule.

The Partnership adopted the Final Rule and ASU 2010-03 effective December 31, 2009, as a change in accounting principle that is inseparable from a change in accounting estimate. Such a change is accounted for prospectively under the authoritative accounting guidance. Comparative disclosures applying the new rules for periods before the adoption of ASU 2010-03 and the Final Rule are not required.

The Partnership’s adoption of ASU 2010-03 and the Final Rule on December 31, 2009 impacted the Partnership’s financial statements and other disclosures for the year ended December 31, 2009 as follows:


	•	All oil and gas reserves volumes presented as of and for the year ended December 31, 2009 were prepared using the updated reserves rules and are not on a basis comparable with prior periods. This change in comparability occurred because the Partnership estimated proved reserves at December 31, 2009 using the updated reserves rules, which required the use of an unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials, and permits the use of reliable technologies to support reserve estimates. Under the previous reserve estimation rules which are no longer in effect, the Partnership’s net proved oil and gas reserves would have been calculated using end-of-period oil and gas prices.

	•	The Partnership’s full cost ceiling test calculation at December 31, 2009 used discounted cash flow models for the Partnership’s estimated proved reserves, which were calculated using the updated reserve rules.

	•	The Partnership historically has applied a policy of using year-end proved reserves to calculate the fourth quarter depletion rate. As a result, the estimate of proved reserves for determining the Partnership’s depletion rate and resulting expense for the fourth quarter of 2009 is not on a basis comparable to prior years.

The impact of the adoption of the SEC final rule on the Partnership’s financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events, as codified in ASC Topic 855, Subsequent Events. The statement is intended to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Particular importance has been placed on the period after the balance sheet date during which management should evaluate events or transactions that may occur leading to recognition within the financial statements or disclosure in the financial statements. This standard is effective for interim and annual periods ending after June 15, 2009. In February 2010, the FASB amended this guidance to remove the requirement to disclose the date through which an entity has evaluated subsequent events for all SEC filers. The adoption of these provisions did not have an impact on our financial position or results of operations. See Note 14 — Subsequent Events.

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(3)	Acquisition and Divestiture of Assets


*(a)*	*Acquisition of Shongaloo Properties*

On January 28, 2009, the Partnership completed an acquisition of 80 producing gas wells located in Arkansas and Louisiana for approximately $48.7 million, including a $5 million deposit that was made in Dec 2008. The acquisition was funded through cash calls to partners combined with borrowings under the Partnership’s credit facility. Total proved reserves of the acquired properties were estimated at 4.2 million barrels of oil equivalent at the date of acquisition.

The Partnership estimates the fair value of the Shongaloo Properties to be approximately $51.6 million, which the Partnership considers to be representative of the price paid by a typical market participant. This measurement resulted in a bargain purchase of $1.2 million recorded in other revenue for the year ended December 31, 2009 due to the increase in commodity prices as of the closing date of acquisition versus the commodity prices at the effective date. The acquisition related costs recognized as expense totaled $0.6 million and is recorded under operating expenses for the year ended December 31, 2009.

The following table summarizes the consideration paid for the Shongaloo Properties and the fair value of the assets acquired and liabilities assumed as of January 28, 2009.

Consideration given to El Paso E&P Company, L.P. (in thousands)


Cash	$	48,700
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	51,600
Asset retirement obligations		(1,700	)
Bargain Purchase		(1,200	)

Total identifiable new assets	$	48,700

Summarized below are the consolidated results of operations for the years ended December 31, 2008 and 2009, on an unaudited pro forma basis, as if the acquisition had occurred on January 1 of each of the periods presented. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Partnership and the statement of revenues and direct operating expenses for the Shongaloo Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations


	2008						2009
	Actual			Pro Forma			Actual			Pro Forma

Shongaloo Properties:
Revenues		281,070			307,510			72,801			73,713
Net Loss		(268,533	)		(248,479	)		(115,414	)		(117,858	)

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


*(b)*	*Divestiture of Non-Core Assets*

The Partnership divested through an auction process certain non-core oil and gas properties in Alabama, Colorado, Louisiana, New Mexico, and Texas representing approximately 8% of total production. The auction took place August 12, 2009 and had an effective date of August 1, 2009 for sold non-operated properties and September 1, 2009 for sold operated properties. The Partnership received $16.3 million for these properties. The proceeds from the 2009 sales of oil and gas properties were recorded as reductions to capitalized costs pursuant to full cost accounting rules, and the cash received was used to reduce borrowings under a credit facility.


(4)	Investments


*(a)*	*Investment in Ute Energy, LLC*

Ute Energy, LLC (UE), a Delaware limited liability company, was formed on February 2, 2005 for the purpose of developing the mineral and surface estate of the Ute Indian Tribe by participating in oil and gas exploration and development, as well as the construction and operation of gas gathering and transportation facilities. UE’s properties are located on the Uintah and Ouray Reservation in northeastern Utah. On July 9, 2007, QR Ute Partners (QR Ute) entered into an agreement to acquire up to 2,000,000 common units of UE, representing 25% of the outstanding units of UE, for $20.0 million, and up to 2,000,000 redeemable units of UE for an additional $20.0 million. QR Ute is a Delaware general partnership owned by QRA1, QRB, QRC and Black Diamond in ownership percentages equal to the ratio of the respective capital contributions to partnerships to the total capital contributions to the Fund. QR Ute purchased 250,000 common units for $2.5 million and 250,000 redeemable units for $2.5 million at closing. During the years ended December 31, 2007 and 2008, QR Ute purchased an additional 1,750,000 common units and 1,750,000 redeemable units for $35.0 million, which fulfilled the funding commitment under the agreement. In April 2009, QR Ute purchased an additional 96,250 common units and 96,250 redeemable units for $1.9 million.

The redeemable units issued to QR Ute accrue a dividend of 12% per annum for the 2007 and 2008 units and 25% per annum for the 2009 units. Dividends are to be paid quarterly either in cash or accrued in-kind. If dividends are paid in-kind, the amount of the dividend is added to the stated value of each redeemable unit ratably each quarter beginning on December 31, 2007 for the 2007 and 2008 units and each quarter beginning on June 30, 2009 for the 2009 units. For the years ended December 31, 2008 and 2009, QRM has accrued dividends of approximately $1.9 million and $3.0 million, respectively, related to the redeemable units.

During the year ended December 31, 2008, the Partnership recorded an impairment of approximately $2.6 million attributed to other than temporary impairment in the carrying value of its investment. This impairment was primarily the result of lower commodity prices for both oil and natural gas at December 31, 2008 and has been recorded on the consolidated statements of operations as an impairment of oil and gas properties. No impairment was recorded during the years ended December 31, 2007 or 2009.

QAH accounts for its’ interest in UE using the equity method of accounting. A summarized balance sheet for UE as of December 31, 2008 and 2009 and a summarized statement of operations for the years ended December 31, 2007, 2008 and 2009 for UE are as follows (the 2008 financial statements of UE below include a restatement which was immaterial to QA Holdings, LP, and therefore, the cumulative effect of which was reported QA Holdings’ equity in earnings of UE for the year ended December 31, 2009).

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Ute Energy, LLC

Summarized Statements of Operations
December 31, 2007, 2008 and 2009


	2007			2008			2009
	(In thousands)

Revenues	$	8,084		$	14,832		$	10,025
Depreciation and amortization expense		5,052			7,792			6,005
Expenses		5,020			7,061			5,822
General and administrative expenses		1,839			2,457			2,232
Total expenses		11,911			17,310			14,059

Interest expense		(3,799	)		(1,156	)		(2,275	)
Other income		43			4,890			4,999
Total other income (expense)		(3,756	)		3,734			2,724

Net income (loss)	$	(7,583	)	$	1,256		$	(1,310	)


*(b)*	*Investment in Marketable Equity Securities*

In 2008, the Partnership purchased $15.3 million of marketable equity securities. During the year ended December 31, 2009, the Partnership sold the remaining $11.5 million of the securities and recorded realized losses of $5.2 million, resulting in a change in the unrealized gain (loss) of $5.6 million. For the period since the original purchase, these securities have a cumulative $7.2 million realized loss. At December 31, 2009, the Partnership did not own any marketable equity securities.


(5)	Long-Term Debt

The Credit Facilities for QRA1 and Black Diamond are held by mortgages on their oil and gas properties and related assets. QRFC’s credit facility is held by the oil and gas properties owned by QAC.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

defined as the applicable British Bankers’ Association London Interbank Offered Rate (LIBOR) for deposits in U.S. dollars.

As of December 31, 2009, the weighted interest rate was 2.73% on outstanding advances of $86.45 million.

The credit agreements contain financial and other covenants, including a current ratio test and an interest coverage test. The Partnership sought and received a waiver for its anticipated 2009 non-compliance with a covenant related to its hedge volumes on oil and gas. The participating banks have granted a waiver until May 1, 2010 for the Partnership to return to compliance. During March 2010, the Partnership liquidated a portion of the hedges and is now compliant with its hedge agreements. The Partnership was in compliance with all other covenants during 2009 and at December 31, 2009.


(6)	Fair Value Measurements

Level 1 — Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 — Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.

Level 3 — Defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions for the asset or liability.

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Level 1		Level 2			Level 3			Total
	(In thousands)

December 31, 2008
Assets:
Commodity derivatives	$	—	$	52,633		$	—		$	52,633
Investments in marketable equity securities		5,839		—			—			5,839
Liabilities:
Interest rate derivatives		—		(2,949	)					(2,949	)
December 31, 2009
Assets:
Commodity derivatives		—		—			7,783			7,783
Liabilities:
Commodity derivatives		—		—			(67,482	)		(67,482	)

Level 1 — Fair Value Measurements

As of December 31, 2008, the fair value of the investment in marketable equity securities and was based on quoted market prices and therefore classified as Level 1 in the fair value hierarchy.

As of December 31, 2009, the Partnership did not have any assets or liabilities measured under a Level 1 fair value hierarchy.

Level 2 — Fair Value Measurements

As of December 31, 2008, all commodity and interest rate derivative instruments were classified as Level 2 in the fair value hierarchy.

As of December 31, 2009, the Partnership did not have assets or liabilities measured under a Level 2 fair value hierarchy.

Level 3 — Fair Value Measurements

As of December 31, 2008, the Partnership did not have any assets or liabilities measured under a Level 3 fair value hierarchy.

As of December 31, 2009, the Partnership had the following instruments classified as Level 3:

Commodity Derivative Instruments — The fair value of the commodity derivative instruments are estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2009 (in thousands):


	Derivatives

Balance at beginning of year	$	—
Total gains or losses (realized or unrealized):
Included in earnings		(63,530	)
Included in other comprehensive income		—
Purchases, issuances and settlements		(45,853	)
Transfers in and out of Level 3		49,684

Balance at end of year	$	(59,699	)

Changes in unrealized gains relating to derivatives still held as of December 31, 2009 $ (108,164)


(7)	Derivatives


*(a)*	*Oil and Gas Commodity Hedges*

Oil and Gas Swaps

As of December 31, 2009, the Partnership had entered into swap transactions with three financial institutions, which are parties to its Credit Facilities, to manage its exposure to changes in the price of oil and natural gas related to the oil and gas properties. The derivative instruments are fixed for floating swap transactions. The following is a summary of the Partnership’s open derivative contracts as of December 31, 2009.


	Oil (WTI)
	Weighted average
Term	$/Bbl		Bbls/d

2010	$	71.20		3,640
2011	$	68.25		2,961
2012	$	67.54		2,611
2013	$	66.80		2,455
2014	$	67.93		766

WTI — West Texas Intermediate

$/Bbl — dollars per barrel

Bbls/d — barrels per day


	Natural Gas (NYMEX)
	Weighted average
Term	$/Mmbtu		Mmbtu/d

2010	$	7.53		11,272
2011	$	7.32		10,079
2012	$	7.04		4,738
2013	$	6.82		4,387
2014	$	6.53		2,632

NYMEX — New York Mercantile Exchange

$/Mmbtu — dollars per million British thermal units

Mmbtu/d — million British thermal units per day

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Gas Basis Contracts


			Permian Basin Area
			Waha
	NYMEX Swap							Basis adjusted
Term	Price		Mmbtu/d		Basis			swap price

Jan 10 — Mar 10	$	9.43		333	$	(0.55	)	$	8.88


			Permian Basin Area
			El Paso, Permian Basin
	NYMEX Swap							Basis adjusted
Term	Price		Mmbtu/d		Basis			swap price

Jan 10 — Mar 10	$	9.43		667	$	(0.70	)	$	8.73


			Oklahoma
			CenterPoint, East
	NYMEX Swap							Basis adjusted
Term	Price		Mmbtu/d		Basis			swap price

Jan 10 — Mar 10	$	9.43		667	$	(0.50	)	$	8.93


			Oklahoma
			ANR, Okla.
	NYMEX Swap							Basis adjusted
Term	Price		Mmbtu/d		Basis			swap price

Jan 10 — Mar 10	$	9.43		333	$	(0.61	)	$	8.82


			Texas Gas Transmission Corp.
	NYMEX Swap							Basis adjusted
Term	Price		Mmbtu/d		Basis			swap price

2010	$	7.02		3,297	$	(0.17	)	$	6.85
2011	$	7.31		2,967	$	(0.16	)	$	7.15
2012	$	6.50		2,630	$	(0.16	)	$	6.34
2013	$	6.50		2,473	$	(0.15	)	$	6.35
2014	$	6.50		2,473	$	(0.15	)	$	6.35

Oil and Gas Collars

In June 2008, the Partnership paid a $1.7 million premium and entered into oil collars (put and call options) that were based on the WTI index. The collars are related to forecasted oil production from July 2008 through December 2009. In November 2008, the Partnership paid a $1.0 million premium and entered into oil collars (put and call options) that were based on the WTI index. The collars are related to forecasted oil production from January 2011 through December 2012. Also in November 2008, the Partnership entered into gas collars that were based on the NYMEX index. The collars are related to forecasted production from January 2010 through December 2010. In December 2008, the Partnership entered into additional oil and gas collars associated with the Shongaloo acquisition. The collars are

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

related to forecasted production from January 2012 through December 2014. The following is a summary of the oil and gas collars as of December 31, 2009.

Weighted

Average

Quantity

Average Floor

Ceiling

Index

Contract

Collars

Volume Per Day

Type

Pricing

Price

Period

Oil

700

Bbls

70.00

110.00

WTI

1/1/2011 —
12/31/2012

Oil

Bbls

60.00

77.93

WTI

1/1/2012 —
12/31/2014

Natural Gas

1,611

Mmbtu

7.00

8.90

NYMEX

1/1/2010 —
12/31/2010

Natural Gas

2,518

Mmbtu

6.50

8.70

Henry Hub

1/1/2012 —
12/31/2014


*(b)*	*Interest Rate Derivative Contract*

During October 2007, the Partnership entered into a derivative instrument for a notional amount of $100.0 million to effectively fix the LIBOR component of the interest rate on its credit facility during the period from October 31, 2007 to October 31, 2009. Under the derivative instrument, the Partnership will make payments to (or receive payments from) the contract counterparty when the variable interest rate of the one-month LIBOR falls below or exceeds the fixed rate of 4.29%. The table below summarizes the realized and unrealized gains and losses the Partnership incurred related to its interest rate derivative instrument for the years ended 2007, 2008 and 2009.


	2007			2008			2009
	(In thousands)

Realized gains (losses) on derivatives(1)	$	84		$	(1,419	)	$	(3,299	)
Unrealized gains (losses) on derivatives(1)		(1,017	)		(1,932	)		2,949

Net realized and unrealized gains (losses) recorded	$	(933	)	$	(3,351	)	$	(350	)


(1)		Included in “Interest expense” in the consolidated statement of operations

The following table reflects the fair value of derivative instruments on our Consolidated Balance Sheet at December 31, 2008 and 2009 (in thousands):


	Asset Derivatives(1)				Liability Derivatives(2)
	2008		2009		2008			2009

Commodity Contracts:
Short-Term	$	49,987	$	7,783	$	—		$	(14,484	)
Long-Term		2,646		—		—			(52,998	)
Interest Rate Contracts:
Short-Term		—		—		(2,949	)		—
Long-Term		—		—		—			—

Total Derivatives:	$	52,633	$	7,783	$	(2,949	)	$	(67,482	)


(1)		Included in derivative assets on our Consolidated Balance Sheet as of December 31, 2008 and 2009.

(2)		Included in derivative liabilities on our Consolidated Balance Sheet as of December 31, 2008 and 2009.

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Partnership has elected not to designate the oil and gas commodity hedges as cash flow hedges under provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as codified in ASC Topic 815, Derivatives and Hedging. As a result, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value of the derivatives are recorded as gains or losses in the accompanying consolidated statements of operations. The table below summarizes the realized and unrealized gains and losses the Partnership incurred related to its oil and natural gas derivative instruments for the years ended December 31, 2007, 2008 and 2009.


	2007			2008			2009
	(In thousands)

Realized gains (losses) on derivatives(1)	$	6,861		$	(34,666	)	$	47,933
Unrealized gains (losses) on derivatives(1)		(157,250	)		169,321			(111,113	)

Net realized and unrealized gains (losses) recorded	$	(150,389	)	$	134,655		$	(63,180	)


(1)		Included as a separate component of other non-operating income (expense) in the consolidated statement of operations


(8)	Asset Retirement Obligations

The Partnership recorded a total of approximately $35.2 million for future asset retirement obligations in connection with the acquisition of the oil and gas properties. The following is a summary of the Partnership’s asset retirement obligations as of and for the years ended December 31, 2008 and 2009.


	2008			2009
	(In thousands)

Beginning of period	$	39,220		$	42,094
Assumed in acquisitions		—			1,732
Divested properties		—			(6,226	)
Revisions to previous estimates		1,338			1,723
Liabilities incurred		23			636
Liabilities settled		(1,491	)		(8,300	)
Accretion expense		3,004			3,585

End of period		42,904			35,244
Less: Current portion of asset retirement obligations		1,500			2,250

Asset retirement obligations — non-current	$	40,594		$	32,994


(9)	Partners’ Equity


(10)	Employee Benefit Plans

The Partnership has a 401(k) savings plan available to all eligible employees. The Partnership matches 100% of employee contributions up to 6% of the employee’s salary. Matching contributions vest immediately. The Partnership made matching cash contributions to the plan for the years ended December 31, 2007, 2008 and 2009 of approximately $268,100, $751,069 and $629,839, respectively.

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(11)	Related-Party Transactions

QAH has obtained services from an affiliated entity related to its normal business operations. The amounts paid for these services were insignificant for the years ended December 31, 2007, 2008 and 2009.


(12)	Commitments


*(a)*	*Operating Lease Commitments*

At December 31, 2009, the Partnership had long-term leases extending through 2013 covering office space and equipment. The Partnership’s future minimum rental payments under these leases as of December 31, 2009 are as follows:


	(In thousands)

Years Ending December 31,
2010	$	793
2011		642
2012		601
2013		5

Approximately 87% of the Partnerships future minimum rental payments are derived from the Houston corporate office space sublease which commenced September 1, 2009 and terminates December 31, 2012. The leasing agreement contains a 4 month rent holiday to be taken from the commencement date. A $1.6 million fee was paid to terminate the Denver corporate office space lease on November 15, 2009. Total rental expense incurred for the years ended December 31, 2007, 2008 and 2009 was approximately $555,000, $950,000 and $3,003,000, respectively.


*(b)*	*Capital Lease Commitments*

At December 31, 2009, the Partnership has a long-term capital lease extending through 2012 covering office furniture and equipment. The Partnership’s future minimum rental payments under this lease as of December 31, 2009 are as follows:


	(In thousands)

Years Ending December 31,
2010	$	51
2011		51
2012		51

Total minimum lease payments		153
Less: Amount representing interest		2

Present value of net minimum lease payments	$	151

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


*(c)*	*Property Reclamation Deposit*

In connection with the 2006 Gulf Coast acquisition between ExxonMobil Corporation and QRM, the Partnership was required to deposit $10 million into an escrow account as security for abandonment and remediation obligations. As of December 31, 2008 and December 31, 2009, $10.7 million was recorded in other assets related to the deposit. In addition to the cash deposit, the Partnership was required to provide a $3 million letter of credit. The agreement requires an additional $3 million letter of credit to be issued in favor of the seller each year through 2012. Letters of credit totaling $12.0 million had been issued as of December 31, 2009. The Partnership is required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to the Partnership until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, the Partnership has the right to request a refund of a portion or all of the property reclamation deposit. Granting of the request is at the seller’s sole discretion.


(13)	Major Customers

During 2007, Shell Trading US Company, ExxonMobil Corporation, and ConocoPhillips Company accounted for 29%, 16% and 13%, respectively, of the Partnership’s revenues.

During 2008, Shell Trading US Company accounted for 51% of the Partnership’s revenues and was the only customer accounting for more than 10% of the Partnership’s revenues.

During 2009, the customers accounting for more than 10% of the Partnership’s revenues were, Shell Trading US Company (19%), Sunoco Inc. R&M (12%) and Plains Marketing LP (11%).

Because there are numerous other parties available to purchase the Partnership’s oil and gas production, the Partnership believes that the loss of any individual purchaser would not materially affect its ability to sell its natural gas or crude oil production.


(14)	Subsequent Events

Quantum Resources Management LLC, a wholly owned subsidiary of the Partnership, signed a purchase and sale agreement on March 31, 2010 to acquire certain oil and gas assets from Denbury Resources, Inc. for $900 million. The assets are located in the Permian Basin, Mid Continent and East Texas. The current production is approximately 12,000 boe/day net. The proved reserves are estimated to be 77 Mmboe at May 1, 2010. The acquisition price is expected to be paid in cash from the proceeds of a combination of equity (cash calls to partners) and debt and is expected to close in mid-May.

Quantum Resources Management LLC, a wholly owned subsidiary of the Partnership, signed and closed a purchase agreement on March 31, 2010 to acquire land within the Jay field from International Paper Company for $3.1 million.

The Partnership has evaluated events subsequent to December 31, 2009 through the date of issuance of these financial statements on April 30, 2010.

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(15)	Supplemental Oil and Gas Disclosures


*(a)*	*Capitalized Costs*

The following table sets forth the capitalized costs related to the Partnership’s oil and natural gas producing activities at December 31, 2008 and 2009 (in thousands):


	2008			2009

Proved properties	$	677,228		$	709,552
Less: Accumulated depreciation, depletion, amortization and impairment		(544,020	)		(589,694	)

Proved properties, net		133,208			119,858
Unproved properties		—			—

Total oil and gas properties, net	$	133,208		$	119,858

Pursuant to the FASB’s authoritative guidance on asset retirement obligations, net capitalized costs include asset retirement costs of $38.1 million and $29.6 million at December 31, 2008 and 2009, respectively.


*(b)*	*Costs Incurred*

The following table sets forth the capitalized costs incurred in the Partnership’s property acquisition, exploration and development activities for the years ended December 31, 2007, 2008 and 2009 (in thousands):


	2007		2008		2009

Acquisition of proved properties	$	17,154	$	391	$	49,145
Development costs		41,128		88,916		7,152

Total costs incurred for acquisition and development activities	$	58,282	$	89,307	$	56,297


*(c)*	*Estimated Proved Reserves (Unaudited)*

Recent SEC and FASB Guidance:

In December 2008 the SEC published the final rules and interpretations updating its oil and gas reporting requirements. The Partnership adopted the rules effective December 31, 2009, and the rule changes, including those related to pricing and technology, are included in the Partnership’s reserve estimates.

In January 2010 the FASB aligned ASC Topic 932, with the aforementioned SEC requirements. Please refer to the section entitled New Accounting Pronouncements under Note 2 — Summary of Significant Accounting Policies for additional discussion regarding both adoptions.

Third Party Reserves Estimates:

The reserve estimates at December 31, 2007 and 2008 in the table below were based on reserve reports prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers, using the FASB rules in effect at each year end. The reserve estimates at December 31, 2009 presented in the table below were based on reserve reports prepared by Miller & Lents, Ltd., independent reserve engineers, using the new FASB and SEC rules in effect at December 31, 2009. See Note 2 — Summary of Significant Accounting Policies for additional discussion regarding both adoptions.

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oil and Gas Reserve Quantities:

Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangement, but not on escalations based on future conditions. All of the Partnership’s oil and natural gas producing activities were conducted within the continental United States.

Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as “proved developed reserves” only after testing by a pilot project or after the operations of an installed program has confirmed through production response that the increased recovery will be achieved.

The Partnership emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Following is a summary of the proved developed and total proved oil and natural gas reserves attributed to the Partnership’s operations (in thousands):


	Oil			Natural gas
	(MBbl)			(MMcf)
	(In thousands)

Proved reserves:
Balance, January 1, 2007		23,505			88,850
Purchases of reserves in place		1,197			4,870
Revisions of previous estimates		333			636
Production		(1,788	)		(5,476	)

Balance, December 31, 2007		23,247			88,880
Purchase of reserves in place		—			—
Revisions of previous estimates		(13,312	)		(48,547	)
Production		(1,753	)		(5,590	)

Balance, December 31, 2008		8,182			34,743
Purchase of reserves in place		1,589			20,169
Sale of reserves in place		(442	)		(5,981	)
Revisions of previous estimates		2,011			1,760
Production		(946	)		(5,359	)

Balance, December 31, 2009		10,394			45,332

Proved developed reserves:
December 31, 2007		19,508			80,813
December 31, 2008		6,301			33,224
December 31, 2009		8,757			44,879

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QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Purchases of Reserves in Place:

The 1,589 MBbl of oil and 20,169 MMcf of natural gas purchased in 2009, was associated with the Shongaloo Properties acquisition. See Section entitled Acquisition of Shongaloo Properties under Note 3 — Acquisition and Divestitures of Assets for additional discussion. The Partnership did not purchase any reserves in place in 2008. 1,197 MBbl of oil and 4,870 MMcf of natural gas was purchased in 2007 in our Gulf Coast region.

Sale of Reserves in Place:

In 2009, the Partnership sold a portion of its non-core oil and gas properties in Alabama, Colorado, Louisiana, New Mexico and Texas representing approximately 8% of total production. See Section entitled Divestiture of Non-core Assets under Note 3 — Acquisition and Divestitures of Assets for additional discussion.

Revisions of Previous Estimates:

In 2009, the Partnership had net positive revisions of 2,011 MBbl of oil and 1,760 MMcf of natural gas, primarily due to higher commodity prices in 2009 as compared to the prices at the end of 2008.

In 2008, the Partnership had net negative revisions of 13,312 MBbl of oil and 48,547 MMcf of natural gas. The reserves in the Jay Field were deemed uneconomic at December 31, 2008. The volumes removed were 1,330 MBbl and 17,109 MMcf. The negative revisions were attributable to higher operating costs and lower prices for production.

In 2007, the Partnership had net positive revision of 333 MBbl of oil and 636 MMcf of natural gas, which were not deemed significant.


*(d)*	*Standardized Measure of Discounted Future Net Cash Flows (Unaudited)*

Future oil and natural gas sales and production and development costs have been estimated in accordance with the Final Rule. See section entitled New Accounting Pronouncements under Note 2 — Summary of Significant Accounting Policies for additional discussion regarding adoption.

The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural reserves, less future development, production, plugging and abandonment costs, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The index prices were $92.50/Bbl for oil and $6.79/MMbtu for natural gas at December 31, 2007, $41.00/Bbl for oil and $5.71/MMbtu for natural gas at December 31, 2008, and the unweighted arithmetic average first-day of-the-month prices for the prior 12 months were $61.18/Bbl for oil and $3.87/MMbtu for natural gas at December 31, 2009. 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. The impact of the adoption of the FASB’s authoritative guidance on the SEC oil and gas reserve estimation final rule on our financial statements is not practicable to estimate due to the operation and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

F-67

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Changes in the demand for oil and natural gas, inflation, and other factors made such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of current market value of the proved reserves attributable to the Partnership’s reserves.

The estimated standardized measure of discounted future net cash flows relating to the Partnership’s proved reserves at December 31, 2007, 2008 and 2009 is shown below (in thousands):


	2007			2008			2009

Future cash inflows	$	2,684,296		$	519,797		$	707,028
Future production costs		(1,104,037	)		(267,822	)		(295,678	)
Future development costs		(135,246	)		(29,637	)		(23,713	)

Future net cash flows		1,445,013			222,338			387,637
10 percent annual discount		(666,194	)		(90,754	)		(170,762	)

Standardized measure of discounted future net cash flows relating to proved reserves	$	778,819		$	131,584		$	216,875

The above table does not include the effects of income taxes on future net revenues because as of December 31, 2007, 2008 and 2009, the Partnership was not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to the Partners.

The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to the Partnership’s proved oil and natural gas reserves for the years ended December 31, 2007, 2008 and 2009 (in thousands):


	2007			2008			2009

Beginning of period	$	451,041		$	778,820		$	131,584
Purchases of reserves in place		42,039			—			51,202
Sales of reserves in place		—			—			(10,106	)
Revisions of previous estimates		9,436			(208,042	)		33,930
Changes in future development cost, net		(38,888	)		75,446			3,149
Development cost incurred during the year that reduce future development costs		6,901			9,921			1,853
Net change in prices		306,823			(384,057	)		51,552
Sales, net production costs		(71,798	)		(127,756	)		(23,724	)
Changes in timing and other		28,162			(90,630	)		(35,723	)
Accretion of discount		45,104			77,882			13,158

End of period	$	778,820		$	131,584		$	216,875

QA Holdings share of Ute Energy, LLC

The following disclosures required under GAAP represent QA Holding’s share of UE’s reserves and UE’s oil and gas operations, which are all located in the Note 4 in our consolidated financial statements contain additional information regarding our relationship with UE.

F-68

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


*(a)*	*Capitalized Costs*

The following table summarizes the carrying value of our portion of UE’s consolidated oil and gas assets at December 31, and 2009 (in thousands):


	2009

Proved properties	$	12,020
Less: Accumulated depreciation, depletion, amortization and impairment		(3,705	)

Proved properties, net		8,315
Unproved properties		268

Total oil and gas properties, net	$	8,583

Pursuant to the FASB’s authoritative guidance on asset retirement obligations, net capitalized costs include asset retirement costs of $360 thousand at December 31, 2009.


*(b)*	*Costs Incurred*

The following table sets forth our share of capitalized costs incurred in UE’s property acquisition, exploration and development activities for the year ended December 31, 2009 (in thousands):


	2009

Acquisition of proved properties		—
Development costs	$	2,787

Total costs incurred for acquisition and development activities	$	2,787


*(c)*	*Estimated Proved Reserves*

Oil and Gas Reserve Quantities:

All of UE’s oil and natural gas producing activities were conducted within the continental United States. Following is a summary of our share of the proved developed and total proved oil, NGLs and natural gas reserves attributed to UE’s operations (in thousands):


	Oil & NGLs			Natural gas
	(MBbl)			(MMcf)
	(In thousands)

Proved reserves:
Balance, December 31, 2008		227			900
Extensions, discoveries and other additions		281			660
Divesture of reserves		(1	)		(38	)
Revisions of previous estimates		551			1,274
Production		(55	)		(193	)

Balance, December 31, 2009		1,003			2,603

Proved developed reserves:
December 31, 2009		283			1,078

Revisions of Previous Estimates:

In 2009, UE had net positive revisions of 551 MBbl of oil and NGLs and 1,274 MMcf of natural gas, primarily due to certain proved undeveloped locations being economical at December 31, 2009.

F-69

QA HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


*(d)*	*Standardized Measure of Discounted Future Net Cash Flows*

Our share of UE’s estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The were unweighted arithmetic average first-day of-the-month prices for the prior 12 months were $49.80/Bbl for oil and $3.14/MMbtu for natural gas at December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

The estimated standardized measure of discounted future net cash flows relating to our share of UE’s proved reserves at December 31, 2009 is shown below (in thousands):


	2009

Future cash inflows	$	57,291
Future production costs		(23,008	)
Future development costs		(15,711	)

Future net cash flows		18,572
10 percent annual discount		(9,625	)

Standardized measure of discounted future net cash flows relating to proved reserves	$	8,947

The above table does not include the effects of income taxes on future net revenues because as of December 31, 2009, UE was not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to the Partners of UE.

The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to our share of UE’s proved oil and NGLs and natural gas reserves for the year ended December 31, 2009 (in thousands):


	2009

Beginning of period	$	3,514
Extensions, discoveries and other additions		2,952
Sales of reserves in place		(65	)
Revisions of previous estimates		2,374
Changes in future development cost, net		210
Development cost incurred during the year that reduce future development costs		106
Net change in prices		192
Sales, net production costs		(1,340	)
Changes in timing and other		653
Accretion of discount		351

End of period	$	8,947

F-70

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

QA Global GP, LLC:

In our opinion, the accompanying statements of revenues and direct operating expenses present fairly, in all material respects, the revenue and direct operating expenses of the Encore properties which were acquired from Denbury Resources, Inc. by Quantum Resources Management, LLC (the “Acquired Encore Properties”) as described in Note 1 for each of the three years ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying financial statements reflect the revenues and direct operating expenses of the Acquired Encore Properties as described in Note 1 and is not intended to be a complete presentation of the financial position, results of operations or cash flows of the Acquired Encore Properties.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
September 29, 2010

F-71

ACQUIRED PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

1. Basis of Presentation

The accompanying statements present the revenues and direct operating expenses of working interests of certain oil and natural gas properties and related assets, primarily located in the Permian Basin in West Texas and southeastern New Mexico; the Mid-continent area, which includes the Anadarko Basin in Oklahoma, Texas, and Kansas; and the East Texas Basin (“Acquired Properties”) acquired by Quantum Resources Management, LLC (“Quantum”) on May 14, 2010 from Encore Operating L.P. (“Encore”) for the years ended December 31, 2007, 2008, and 2009.

The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Encore. Revenues and direct operating expenses relate to the historical net revenue interest and net working interest, respectively, in the Acquired Properties. Natural gas, oil and natural gas liquids revenues are recognized when production is sold to a purchaser at a fixed or determinable price when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues are reported net of overriding and other royalties due to third parties. Direct operating expenses include lease and well repairs, production and ad valorem taxes, gathering and transportation, maintenance, utilities, payroll and other direct operating expenses.

During the periods presented, the Acquired Properties were not accounted for as a separate division by Encore and therefore certain costs such as depreciation, depletion and amortization, accretion of asset retirement obligation, general and administrative expenses, interest, and corporate income taxes were not allocated to the individual properties. Complete separate financial statements prepared in accordance with generally accepted accounting principles are not presented because the information necessary to prepare such complete statements, reflecting financial position, results of operations, stakeholder equity and cash flows of the Acquired Properties, is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the historical statements of revenues and direct operating expenses of the Acquired Properties are presented in lieu of the financial statements required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X. The results set forth in these financial statements may not be representative of future operations.

2. Unaudited Interim Statements

The accompanying statements of revenues and direct operating expenses for the three month periods ended March 31,2010 and 2009 are unaudited. The unaudited interim statements of revenues and direct operating expenses have been prepared on the same basis as the annual statement of revenues and direct operating expenses and, in the opinion of management, reflect all adjustments necessary to fairly present the Acquired Properties’ excess of revenue over direct operating expenses for the three month periods ended March 31, 2010 and 2009.

3. Subsequent Events

Management has evaluated events subsequent to December 31, 2009 through the date of issuance of these statements of revenues and direct operating expenses on September 29, 2010.

4. Supplemental Oil and Gas Reserve and Standardized Measure Information (Unaudited)

The following oil and gas reserve information was prepared by Quantum based upon information provided by Encore.

Estimated Quantities of Oil and Gas Reserves. All of the Acquired Properties and associated reserves are located in the continental United States. The following table presents the estimated

F-73

ACQUIRED PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

remaining net proved and proved developed oil and gas reserves of the Acquired Properties at December 31, 2007, 2008, and 2009, estimated by Encore’s petroleum engineers, and the related summary of changes in estimated quantities of net remaining proved reserves during the year.


	2007						2008						2009
	Oil(1)			Gas			Oil(1)			Gas			Oil(1)			Gas
	(MBbls)			(MMcf)			(MBbls)			(MMcf)			(MBbls)			(MMcf)

Proved Reserves
Beginning of year		16,186			64,592			16,413			89,703			13,614			107,997
Revisions of previous estimates		851			6,174			(2,478	)		3,005			882			(4,767	)
Extensions and discoveries		254			26,496			589			25,394			236			11,429
Acquisitions of minerals in place		—			—			—			—			5,822			84,928
Production		(878	)		(7,559	)		(910	)		(10,105	)		(1,052	)		(15,084	)

End of year		16,413			89,703			13,614			107,997			19,502			184,503

Proved developed reserves, end of year		11,867			64,896			9,496			90,111			15,136			163,200


(1)		Includes NGLs

Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows as of December 31, 2007, 2008, and 2009 was computed by applying the year end prices for 2007 and 2008 and the twelve month average for the first day of each month for 2009 of oil and gas ($7.47, $5.62, and $3.83 per mcf of gas, respectively, and $96.01, $44.60, and $61.18 per barrel of oil, respectively), adjusted for transportation fees and regional price differentials, to the estimated future production of proved oil and gas reserves less estimated future expenditures to be incurred in developing and producing the proved reserves, discounted using an annual rate of 10% to reflect the estimated timing of the future cash flows. As of December 31, 2007, 2008 and 2009, the relevant average realized prices for oil were $68.26, $95.71 and $56.46 per barrel of oil, respectively, and $6.78, $8.24 and $3.75 per Mcf, respectively. Income taxes are excluded because the property interests included in the acquisition represent only a portion of a business for which income taxes are not estimable. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties. Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the Acquired Properties’ oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and costs. The following table sets forth estimates of

F-74

ACQUIRED PROPERTIES

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

the standardized measure of discounted future net cash flows relating to proved oil and gas reserves as of December 31, 2007, 2008, and 2009 (in thousands).


	As of December 31,
	2007			2008			2009

Future cash inflows from production	$	2,057,805		$	1,160,702		$	1,746,352
Future production costs		(677,317	)		(481,453	)		(739,022	)
Future development costs		(96,497	)		(80,255	)		(64,968	)

Future net cash flows		1,283,991			598,994			942,362
10% annual discount		(724,233	)		(311,995	)		(456,130	)

Standardized measure of discounted future net cash flows	$	559,758		$	286,999		$	486,232

Changes in the standardized measure of future net cash flows related to proved oil and gas reserves are as follows for the year ended December 31, 2007, 2008, and 2009 (in thousands).


	Year Ended December 31,
	2007			2008			2009

Standardized measure, beginning of year	$	293,151		$	559,758		$	286,999
Revenues less production and other costs		(80,724	)		(131,944	)		(83,381	)
Net changes in prices, production and other costs		211,870			(275,330	)		31,401
Net development costs incurred		29,463			29,463			29,203
Net changes in future development costs		(15,798	)		6,336			471
Extensions, discoveries and improved recoveries		58,891			50,552			13,591
Revisions of previous quantity estimates		33,370			(25,924	)		14,892
Purchases of minerals in place		—			—			162,774
Accretion of discount		29,315			55,976			28,700
Timing differences and other		220			18,112			1,582


Standardized measure, end of year	$	559,758		$	286,999		$	486,232

F-75

Independent Auditors’ Report

The Board of Directors and Stockholders
EXCO Resources, Inc.:

We have audited the accompanying statements of revenues and direct operating expenses of EXCO Resources, Inc.’s divested properties subsequently acquired by Quantum Resources Management, LLC (“the Properties”) for the years ended December 31, 2007 and December 31, 2008; and the period from January 1, 2009 to August 11, 2009. These statements are the responsibility of the Properties’ management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the properties’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements referred to above were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. The statements are not intended to be a complete presentation of the revenues and expenses for the Properties.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of EXCO Resources, Inc.’s divested properties subsequently acquired by Quantum Resources Management, LLC for the years ended December 31, 2007 and December 31, 2008; and the period from January 1 to August 11, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

September 27, 2010

F-76

EXCO RESOURCES, INC.’S DIVESTED PROPERTIES
SUBSEQUENTLY ACQUIRED BY QUANTUM RESOURCES MANAGEMENT, LLC

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
PERIOD FROM JANUARY 1, 2009 TO AUGUST 11, 2009
AND THE YEARS ENDED DECEMBER 31, 2008 AND 2007


Note 1.	Basis of Presentation

On June 29, 2009, EXCO Resources, Inc. (EXCO) entered into an agreement with Encore Operating, L.P. (Encore) to sell its Norge Marchand Unit in Grady County, Oklahoma, other selected Oklahoma, Kansas and Texas Panhandle assets, and a separate agreement to sell its Gladewater Field and Overton Field assets in Gregg, Upshur and Smith Counties, Texas (Divested Properties). Both asset sales closed on August 11, 2009 for cash purchase prices of $197.7 million and $154.3 million, respectively, after final closing adjustments. On March 9, 2010, Encore was merged with and into Denbury Resources Inc. (Denbury). On May 14, 2010, Denbury sold certain oil and natural gas properties and related assets to Quantum Resources Management, LLC (Quantum). A portion of the properties acquired by Quantum were part of EXCO’s divested properties to Encore. The accompanying statements of revenues and direct operating expenses are related to only the properties divested by EXCO which were subsequently acquired by Quantum (Quantum Properties).

Historical financial statements prepared in accordance with accounting principles generally accepted in the United States of America have never been prepared for the Quantum Properties. The accompanying statements of revenues and direct operating expenses related to the Quantum Properties were prepared from the historical accounting records of EXCO.

Certain indirect expenses, as further described in Note 4, were not allocated to the Quantum Properties and have been excluded from the accompanying statements. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and may not be indicative of the performance of the properties on a stand-alone basis.

These statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting financial position, results of operations, stakeholders’ equity and cash flows of the Quantum Properties and are not necessarily indicative of the results of operations for the Quantum Properties going forward.


Note 2.	Significant Accounting Policies

Use of Estimates

Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual results could be different from those estimates.

Revenue Recognition

EXCO uses the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. There were no significant imbalances with other revenue interest owners during any of the periods presented in these statements.

Direct Operating Expenses

Direct operating expenses, which are recognized on an accrual basis, relate to the direct expenses of operating the Quantum Properties. The direct operating expenses include lease operating, ad valorem tax and production tax expense. Lease operating expenses include lifting costs, well repair expenses, surface repair expenses, well workover costs and other field expenses. Lease operating expenses also

F-78

EXCO RESOURCES, INC.’S DIVESTED PROPERTIES

SUBSEQUENTLY ACQUIRED BY QUANTUM RESOURCES MANAGEMENT, LLC

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

include expenses directly associated with support personnel, support services, equipment and facilities directly related to oil and natural gas production activities.


Note 3.	Contingencies

The activities of the Quantum Properties are subject to potential claims and litigation in the normal course of operations. EXCO management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Quantum Properties.


Note 4.	Excluded Expenses

The Quantum Properties were part of a much larger enterprise prior to the date of the sale by EXCO to Encore. Indirect general and administrative expenses, interest, income taxes, and other indirect expenses were not allocated to the Quantum Properties and have been excluded from the accompanying statements. In addition, any allocation of such indirect expenses may not be indicative of costs which would have been incurred by the Quantum Properties on a stand-alone basis.

Also, depreciation, depletion, and amortization have been excluded from the accompanying statements of revenues and direct operating expenses as such amounts would not be indicative of the depletion calculated on the Quantum properties on a stand-alone basis.


Note 5.	Supplemental Information relating to oil and natural gas producing activities (unaudited)

On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date. Among other things, Release No. 33-8995:


	•	Revises a number of definitions relating to oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves;

	•	Permits the use of new technologies for determining oil and natural gas reserves;

	•	Requires the use of average prices for the trailing twelve-month period in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the ceiling limitation test, in place of a single day price as of the end of the fiscal year;

	•	Permits the disclosure in filings with the SEC of probable and possible reserves and sensitivity of our proved oil and natural gas reserves to changes in prices;

	•	Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and

	•	Requires a discussion of the internal controls in place in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates.

The reserve information was generated using the reserve reporting rules in place as of August 11, 2009.

F-79

EXCO RESOURCES, INC.’S DIVESTED PROPERTIES

SUBSEQUENTLY ACQUIRED BY QUANTUM RESOURCES MANAGEMENT, LLC

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

Estimated Quantities of Proved Reserves

EXCO retained independent engineering firms to provide annual year-end estimates of its future net recoverable proved oil and natural gas reserves for 2007 and 2008. Estimates of Proved Reserves as of August 11, 2009 were estimated by EXCO’s internal engineering staff. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under the then existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves estimated to be recovered through existing wells. Proved Undeveloped Reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operations is required. All of the Quantum Properties’ Proved Reserves are located onshore in the continental United States of America.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

The following table sets forth estimates of the proved oil and natural gas reserves (net of royalty interests) for the Quantum Properties and changes therein, for the periods indicated.

Estimated Quantities of Proved Reserves


	Oil			Natural Gas
	(Bbls)			(Mcf)			Mcfe(1)
	(Amounts in thousands)

January 1, 2007		1,774			131,279			141,923
Purchases of reserves in place		3,986			33,658			57,574
Extensions and discoveries		8			1,544			1,592
Revisions of previous estimates		(260	)		(14,872	)		(16,432	)
Production		(384	)		(10,550	)		(12,854	)

December 31, 2007		5,124			141,059			171,803
Purchases of reserves in place		—			—			—
Extensions and discoveries		26			5,187			5,343
Revisions of previous estimates		123			13,335			14,073
Production		(520	)		(11,745	)		(14,865	)

December 31, 2008		4,753			147,836			176,354
Purchases of reserves in place		—			—			—
Extensions and discoveries		—			—			—
Revisions of previous estimates		804			(30,235	)		(25,411	)
Production		(273	)		(6,156	)		(7,794	)

August 11, 2009		5,284			111,445			143,149


(1)		Mcfe — one thousand cubic feet equivalent calculated by converting one Bbl of oil to six Mcf of natural gas.

F-80

EXCO RESOURCES, INC.’S DIVESTED PROPERTIES

SUBSEQUENTLY ACQUIRED BY QUANTUM RESOURCES MANAGEMENT, LLC

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

Standardized Measure of Discounted Future Net Cash Flows

We have summarized the Standardized Measure related to our proved oil, natural gas and NGL reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on year end prices, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in place and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.

Estimated Quantities of Proved Developed Reserves


	Oil		Natural gas
	(Bbls)		(Mcf)		Mcfe(1)
	(In thousands)

August 11, 2009		5,150		98,356		129,256
December 31, 2008		4,573		132,185		159,623
December 31, 2007		4,756		112,823		141,359


(1)		Mcfe — one thousand cubic feet equivalent calculated by converting one Bbl of oil to six Mcf of natural gas.

F-81

EXCO RESOURCES, INC.’S DIVESTED PROPERTIES

SUBSEQUENTLY ACQUIRED BY QUANTUM RESOURCES MANAGEMENT, LLC

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

Standardized Measure of Oil and Gas


	(Amounts in thousands)

August 11, 2009:
Future cash inflows	$	753,192
Future production costs		(284,671	)
Future development costs		(65,742	)
Future income taxes		(45,215	)

Future net cash flows		357,564
Discount of future net cash flows at 10% per annum		(171,919	)

Standardized measure of discounted future net cash flows	$	185,645

As of December 31, 2008:
Future cash inflows	$	986,230
Future production costs		(425,031	)
Future development costs		(107,331	)
Future income taxes		(36,069	)

Future net cash flows		417,799
Discount of future net cash flows at 10% per annum		(200,654	)

Standardized measure of discounted future net cash flows	$	217,145

As of December 31, 2007:
Future cash inflows	$	1,368,779
Future production costs		(375,087	)
Future development costs		(112,823	)
Future income taxes		(167,645	)

Future net cash flows		713,224
Discount of future net cash flows at 10% per annum		(323,371	)

Standardized measure of discounted future net cash flows	$	389,853

During recent years, prices paid for oil and natural gas have fluctuated significantly. The spot prices at August 11, 2009 and December 31, 2008 and 2007 used in the above table were $69.45, 44.60 and $95.92 per Bbl of oil, respectively, and $3.55, $5.71 and $6.80 per Mmbtu of natural gas, respectively, in each case adjusted for historical differences.

F-82

EXCO RESOURCES, INC.’S DIVESTED PROPERTIES

SUBSEQUENTLY ACQUIRED BY QUANTUM RESOURCES MANAGEMENT, LLC

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the periods indicated.

Changes in Standardized Measure


	(In thousands)

Period ended August 11, 2009
Sales of oil and natural gas produced, net of production costs	$	(22,381	)
Net changes in prices and production costs		5,177
Extensions and discoveries, net of future development and production costs		—
Previously estimated development costs incurred during the period		14,456
Changes in estimated future development costs-net		2,678
Revisions of previous quantity estimates		(40,485	)
Accretion of discount before income taxes		13,522
Changes in timing and other		(1,128	)
Net change in income taxes		(3,339	)

Net change	$	(31,500	)

Year ended December 31, 2008
Sales of oil and natural gas produced, net of production costs	$	(126,345	)
Net changes in prices and production costs		(175,525	)
Extensions and discoveries, net of future development and production costs		431
Previously estimated development costs incurred during the period		23,944
Changes in estimated future development costs-net		(15,691	)
Revisions of previous quantity estimates		21,780
Accretion of discount before income taxes		45,472
Changes in timing and other		(8,245	)
Net change in income taxes		61,471

Net change	$	(172,708	)

Year ended December 31, 2007
Sales of oil and natural gas produced, net of production costs	$	(81,340	)
Purchases of reserves in place		230,749
Net changes in prices and production costs		89,721
Extensions and discoveries, net of future development and production costs		4,653
Previously estimated development costs incurred during the period		26,078
Changes in estimated future development costs-net		(9,558	)
Revisions of previous quantity estimates		(49,067	)
Accretion of discount before income taxes		22,068
Changes in timing and other		5,507
Net change in income taxes		(41,489	)

Net change	$	197,322

F-83

TABLE OF CONTENTS


ARTICLE I
DEFINITIONS
	Section 1.1	Definitions	A-6
	Section 1.2	Construction	A-24

ARTICLE II
ORGANIZATION
	Section 2.1	Formation	A-24
	Section 2.2	Name	A-25
	Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices	A-25
	Section 2.4	Purpose and Business	A-25
	Section 2.5	Powers	A-25
	Section 2.6	Term	A-25
	Section 2.7	Title to Partnership Assets	A-25

ARTICLE III
RIGHTS OF LIMITED PARTNERS
	Section 3.1	Limitation of Liability	A-26
	Section 3.2	Management of Business	A-26
	Section 3.3	Outside Activities of the Limited Partners	A-26
	Section 3.4	Rights of Limited Partners	A-26

ARTICLE IV
CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS
	Section 4.1	Certificates	A-27
	Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates	A-27
	Section 4.3	Record Holders	A-28
	Section 4.4	Transfer Generally	A-28
	Section 4.5	Registration and Transfer of Limited Partner Interests	A-29
	Section 4.6	Transfer of the General Partner’s General Partner Interest	A-29
	Section 4.7	Restrictions on Transfers	A-30
	Section 4.8	Eligibility Certificates; Ineligible Holders	A-31
	Section 4.9	Redemption of Partnership Interests of Ineligible Holders	A-32

ARTICLE V
CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
	Section 5.1	Organizational Contributions	A-33
	Section 5.2	Contributions by the General Partner and its Affiliates	A-33
	Section 5.3	Contributions by Initial Limited Partners	A-34
	Section 5.4	Interest and Withdrawal	A-34
	Section 5.5	Capital Accounts	A-34
	Section 5.6	Issuances of Additional Partnership Interests	A-37
	Section 5.7	Conversion of Subordinated Units	A-38
	Section 5.8	Limited Preemptive Right	A-38

A-2


	Section 5.9	Splits and Combinations	A-38
	Section 5.10	Fully Paid and Non-Assessable Nature of Limited Partner Interests	A-39
	Section 5.11	Issuance of Class B Units in Connection with Conversion of Management Incentive Fee	A-39

ARTICLE VI
ALLOCATIONS AND DISTRIBUTIONS
	Section 6.1	Allocations for Capital Account Purposes	A-40
	Section 6.2	Allocations for Tax Purposes	A-49
	Section 6.3	Requirement and Characterization of Distributions; Distributions to Record Holders	A-51
	Section 6.4	Distributions of Available Cash from Operating Surplus	A-51
	Section 6.5	Distributions of Available Cash from Capital Surplus	A-52
	Section 6.6	Adjustment of Minimum Quarterly Distribution and Target Distribution	A-52
	Section 6.7	Special Provisions Relating to the Holders of Subordinated Units and Class B Units	A-52
	Section 6.8	Entity-Level Taxation	A-53

ARTICLE VII
MANAGEMENT AND OPERATION OF BUSINESS
	Section 7.1	Management	A-54
	Section 7.2	Certificate of Limited Partnership	A-56
	Section 7.3	Restrictions on the General Partner’s Authority	A-56
	Section 7.4	Reimbursement of the General Partner; Management Incentive Fee	A-56
	Section 7.5	Outside Activities	A-58
	Section 7.6	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members	A-59
	Section 7.7	Indemnification	A-59
	Section 7.8	Liability of Indemnitees	A-61
	Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties	A-61
	Section 7.10	Other Matters Concerning the General Partner	A-63
	Section 7.11	Purchase or Sale of Partnership Interests	A-63
	Section 7.12	Registration Rights of the General Partner and its Affiliates	A-64
	Section 7.13	Reliance by Third Parties	A-66

ARTICLE VIII
BOOKS, RECORDS, ACCOUNTING AND REPORTS
	Section 8.1	Records and Accounting	A-66
	Section 8.2	Fiscal Year	A-66
	Section 8.3	Reports	A-66

ARTICLE IX
TAX MATTERS
	Section 9.1	Tax Returns and Information	A-67
	Section 9.2	Tax Elections	A-67
	Section 9.3	Tax Controversies	A-67
	Section 9.4	Withholding; Tax Payments	A-68

A-3


ARTICLE X
ADMISSION OF PARTNERS
	Section 10.1	Admission of Limited Partners	A-68
	Section 10.2	Admission of Successor General Partner	A-69
	Section 10.3	Amendment of Agreement and Certificate of Limited Partnership	A-69

ARTICLE XI
WITHDRAWAL OR REMOVAL OF PARTNERS
	Section 11.1	Withdrawal of the General Partner	A-69
	Section 11.2	Removal of the General Partner	A-71
	Section 11.3	Interest of Departing General Partner and Successor General Partner	A-71
	Section 11.4	Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages	A-72
	Section 11.5	Withdrawal of Limited Partners	A-73

ARTICLE XII
DISSOLUTION AND LIQUIDATION
	Section 12.1	Dissolution	A-73
	Section 12.2	Continuation of the Business of the Partnership After Dissolution	A-73
	Section 12.3	Liquidator	A-74
	Section 12.4	Liquidation	A-74
	Section 12.5	Cancellation of Certificate of Limited Partnership	A-75
	Section 12.6	Return of Contributions	A-75
	Section 12.7	Waiver of Partition	A-75
	Section 12.8	Capital Account Restoration	A-75

ARTICLE XIII
AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
	Section 13.1	Amendments to be Adopted Solely by the General Partner	A-75
	Section 13.2	Amendment Procedures	A-76
	Section 13.3	Amendment Requirements	A-77
	Section 13.4	Special Meetings	A-77
	Section 13.5	Notice of a Meeting	A-78
	Section 13.6	Record Date	A-78
	Section 13.7	Adjournment	A-78
	Section 13.8	Waiver of Notice; Approval of Meeting; Approval of Minutes	A-78
	Section 13.9	Quorum and Voting	A-79
	Section 13.10	Conduct of a Meeting	A-79
	Section 13.11	Action Without a Meeting	A-79
	Section 13.12	Right to Vote and Related Matters	A-80

ARTICLE XIV
MERGER, CONSOLIDATION OR CONVERSION
	Section 14.1	Authority	A-80
	Section 14.2	Procedure for Merger, Consolidation or Conversion	A-80
	Section 14.3	Approval by Limited Partners	A-82

A-4

FIRST AMENDED AND RESTATED AGREEMENT
OF LIMITED PARTNERSHIP OF QR ENERGY, LP

THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF QR ENERGY, LP dated as of , 2010, is entered into by and between QRE GP, LLC, a Delaware limited liability company, as the General Partner, and The Quantum Aspect Partnership, LP, a Delaware limited partnership, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing or expanding for the long-term the asset base of the Partnership Group from the long-term asset base of the Partnership Group existing immediately prior to such transaction.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period. With respect to a Disposed of Adjusted Property, the Additional Book Basis Derivative items shall be the amount of Additional Book Basis taken into account in computing gain or loss from the disposition of such Disposed of Adjusted Property.

“Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each taxable period of the Partnership, (a) increased by any amounts that such Partner is obligated to

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First Amended and Restated Agreement of Limited Partnership

A-6

restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such taxable period, are reasonably expected to be made to such Partners’s Capital Account in respect of the oil and gas properties of the Partnership Group, (ii) the amount of all losses and deductions that, as of the end of such taxable period, are reasonably expected to be allocated to such Partner in subsequent taxable periods under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such taxable period, are reasonably expected to be made to such Partner in subsequent taxable periods in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the taxable period in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Adjusted Management Incentive Fee Base” shall be an amount that,

(a) through the initial Conversion Election, is equal to the Gross Management Incentive Fee Base;

(b) immediately following any Conversion Election and until the next Calculation Date, is equal to the product of (i) the Adjusted Management Incentive Fee Base in effect immediately prior to the Conversion Election and (ii) one minus the Applicable Conversion Percentage for such Conversion Election; and

(c) as of any Calculation Date following any Conversion Election, is equal to the sum of (i) the product of (x) one minus the Applicable Conversion Percentage for the most recent Conversion Election and (y) the Adjusted Management Incentive Fee Base in effect immediately prior to the most recent Conversion Election; and (ii) the Gross Management Incentive Fee Base as of such Calculation Date less the Gross Management Incentive Fee Base in effect immediately prior to the most recent Conversion Election.

“Adjusted Operating Surplus” means, with respect to any period, (a) Operating Surplus generated with respect to such period; (b) less (i) the amount of any net increase in Working Capital Borrowings (or the Partnership’s proportionate share of any net increase in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to that period; and (ii) the amount of any net decrease in cash reserves (or the Partnership’s proportionate share of any net decrease in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period; and (c) plus (i) the amount of any net decrease in Working Capital Borrowings (or the Partnership’s proportionate share of any net decrease in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to that period; (ii) the amount of any net increase in cash reserves (or the Partnership’s proportionate share of any net increase in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium; and (iii) any net decrease made in subsequent periods in cash reserves for Operating Expenditures initially established with respect to such period to the extent such decrease results in a reduction in Adjusted Operating Surplus in subsequent periods pursuant to

QR Energy, LP

First Amended and Restated Agreement of Limited Partnership

A-7

clause (b)(ii) above. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or 5.5(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Aggregate Quantity of Class B Units” has the meaning assigned to such term in Section 5.11(b).

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property at the time of contribution and in the case of an Adjusted Property, the fair market value of such Adjusted Property on the date of the revaluation event as described in Section 5.5(d), in both cases as determined by the General Partner.

“Agreement” means this First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, as it may be amended, supplemented or restated from time to time.

“Applicable Conversion Percentage” means, in connection with each Conversion Election, the percentage of the applicable Management Incentive Fee that the General Partner elects to convert pursuant to Section 5.11(a) in such Conversion Election; provided, that such percentage shall not be greater than 80%.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of (i) all cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of such Quarter, and (ii) if the General Partner so determines, all or any portion of any additional cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter, less

(b) the amount of any cash reserves established by the General Partner (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) to (i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group

QR Energy, LP

First Amended and Restated Agreement of Limited Partnership

A-8

Member is a party or by which it is bound or its assets are subject or (iii) provide funds for distributions under Section 6.4 or 6.5 in respect of any one or more of the next four Quarters;

provided, that the General Partner may not establish cash reserves pursuant to clause (b) (iii) above unless the General Partner determines that the effect of such reserves would not be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to any of the next four Quarters; and, provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Black Diamond” means Black Diamond Resources, LLC, a Delaware limited liability company, and any successors thereto.

“Board of Directors” means the board of directors or board of managers, as applicable, of the General Partner or, if the General Partner is a limited partnership, the board of directors or board of managers of the general partner of the General Partner.

“Book Basis Derivative Items” means any item of income, deduction, gain or loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Texas shall not be regarded as a Business Day.

“Calculation Date” means December 31 and June 30 of each year.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the

QR Energy, LP

First Amended and Restated Agreement of Limited Partnership

A-9

Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions).

“Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new or the improvement or replacement of existing, capital assets or (c) capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has, or after such capital contribution will have, an equity interest to fund such Group Member’s pro rata share of the cost of the addition or improvement to or the acquisition of existing, or the construction of new or the improvement or replacement of existing, capital assets by such Person, in each case if such addition, improvement, replacement, acquisition or construction is made to increase for the long-term the asset base of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the long-term asset base of the Partnership Group or such Person, as the case may be, existing immediately prior to such addition, improvement, replacement, acquisition or construction.

“Capital Surplus” means Available Cash distributed by the Partnership in excess of Operating Surplus, as described in Section 6.3(a).

“Carrying Value” means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, Simulated Depletion, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination; provided that the Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.5(d) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means a certificate in such form (including global form if permitted by applicable rules and regulations) as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Partnership Interests. The initial form of certificate approved by the General Partner for Common Units is attached as Exhibit A to this Agreement.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“Citizenship Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen Holder.

“claim” (as used in Section 7.12(c)) is defined in Section 7.12(c).

“Class B Units” means a Unit representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Class B Units in this Agreement.

“Closing Date” means the first date on which Common Units are sold by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

QR Energy, LP

First Amended and Restated Agreement of Limited Partnership

A-10

“Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange on which the respective Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the primary reporting system then in use in relation to such Limited Partner Interests of such class, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Combined Interest” is defined in Section 11.3(a).

“Commences Commercial Service” means a Capital Improvement begins producing in paying quantities or is first put into commercial service by a Group Member following completion of construction, acquisition, development and testing, as applicable.

“Commission” means the United States Securities and Exchange Commission.

“Common Unit” means a Unit representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not refer to, or include, any Subordinated Unit or Class B Unit prior to its conversion into a Common Unit pursuant to the terms hereof.

“Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, with respect to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).

“Conflicts Committee” means a committee of the Board of Directors composed entirely of one or more directors who (a) are not (i) officers or employees of the General Partner, (ii) officers, directors or employees of any Affiliate of the General Partner (other than Group Members) or (iii) holders of any ownership interest in the General Partner or any of its Affiliates, including any Group Member other than Common Units, or securities exercisable, convertible into or exchangeable for Common Units and (b) also meet the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which any class of Partnership Interests is listed or admitted to trading.

“Contributed Property” means each property, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Contribution Agreement” means that certain Contribution, Conveyance and Assumption Agreement, dated as of , 2010, among the General Partner, the Partnership, the Operating

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First Amended and Restated Agreement of Limited Partnership

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Partnership and certain other parties, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.

“Conversion Election” means an election by the General Partner to convert a portion of the Management Incentive Fee pursuant to Section 5.11(a).

“Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum of the Common Unit Arrearages with respect to an Initial Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and the second sentence of Section 6.5 with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

“Current Market Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

“Deferred Issuance and Distribution” means both (a) the issuance by the Partnership of a number of additional Common Units that is equal to the excess, if any, of (x) 2,250,000 minus (y) the aggregate number, if any, of Common Units actually purchased by and issued to the Underwriters pursuant to the Over-Allotment Option on the Option Closing Date(s) and (b) the payment by the Partnership to the Fund Group of cash in an amount equal to the aggregate amount of cash, if any, contributed by the Underwriters to the Partnership on or in connection with any Option Closing Date with respect to Common Units issued by the Partnership upon the applicable exercise of the Over-Allotment Option as described in Section 5.3(b), if any.

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or Section 11.2.

“Disposed of Adjusted Property” has the meaning assigned to such term in Section 6.1(d)(xii)(B).

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“Eligible Citizen Holder” means a Limited Partner whose nationality, citizenship or other related status would not, in the determination of the General Partner, create a substantial risk of cancellation or forfeiture of any property in which a Group Member has an interest.

“Eligibility Certification” means a Citizenship Certification or a Rate Eligibility Certification.

“Estimated Incremental Quarterly Tax Amount” is defined in Section 6.8.

“Estimated Maintenance Capital Expenditures” means an estimate made in good faith by the Board of Directors (with the concurrence of the Conflicts Committee) of the average quarterly Maintenance Capital Expenditures that the Partnership will need to incur over the long term to maintain the long-term asset base of the Partnership Group (including the Partnership’s proportionate share of the average quarterly Maintenance Capital Expenditures of its Subsidiaries that are not wholly owned) existing at the time the estimate is made. The Board of Directors (with the concurrence of the Conflicts Committee) will be permitted to make such estimate in any manner it determines reasonable. The

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estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of future Estimated Maintenance Capital Expenditures. The Partnership shall disclose to its Partners any change in the amount of Estimated Maintenance Capital Expenditures in its reports made in accordance with Section 8.3 to the extent not previously disclosed. Any adjustments to Estimated Maintenance Capital Expenditures shall be prospective only.

“Event of Withdrawal” is defined in Section 11.1(a).

“Excess Distribution” is defined in Section 6.1(d)(iii)(A).

“Excess Distribution Unit” is defined in Section 6.1(d)(iii)(A).

“Final Subordinated Units” is defined in Section 6.1(d)(x)(A).

“Fund Group” means QRAI, QRB, QRC, QAB, QAC and Black Diamond, collectively.

“General Partner” means QRE GP, LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it) and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“General Partner Unit” means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A General Partner Unit is not a Unit.

“Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s-length transaction.

“Gross Management Incentive Fee Base” shall be an amount, calculated as of each Calculation Date, equal to the sum of (i) the future net revenue of the Partnership Group’s estimated proved oil and natural gas reserves discounted to present value at 10% and calculated as of such Calculation Date in accordance with the requirements of the Commission, adjusted for the present value of the Partnership Group’s derivative instruments and (ii) the value as of such Calculation Date of all assets of the Partnership Group other than oil and natural gas reserves that principally produce “qualifying income” as defined in Section 7704 of the Code, at such value as may be determined the Board of Directors (with the concurrence of the Conflicts Committee); provided that if the Board of Directors cannot determine a value with the concurrence of the Conflicts Committee, an independent investment banking firm or other independent expert selected by the Board of Directors (with the concurrence of the Conflicts Committee) will determine the fair market value; provided further that if the Board of Directors cannot agree upon an expert with the Conflicts Committee, then an expert chosen by agreement of the experts selected by (i) the members of the Board of Directors other than the members of the Conflicts Committee and (ii) the Conflicts Committee, will determine the fair market value.

“Group” means a Person that with or through any of its Affiliates or Associates has any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

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“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Growth Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements, and shall not include Maintenance Capital Expenditures or Investment Capital Expenditures. Growth Capital Expenditures shall include interest (and related fees) on debt incurred to finance the construction of a Capital Improvement and paid in respect of the period beginning on the date that a Group Member enters into a binding obligation to commence construction of a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service and the date that such Capital Improvement is abandoned or disposed of. Debt incurred to fund such construction period interest payments or to fund distributions in respect of equity issued to fund the construction of a Capital Improvement as described in clause (a)(iv) of the definition of Operating Surplus shall also be deemed to be debt incurred to finance the construction of a Capital Improvement. Where capital expenditures are made in part for Growth Capital Expenditures and in part for other purposes, the General Partner shall determine the allocation between the amounts paid for each.

“Hedge Contract” means any exchange, swap, forward, cap, floor, collar, option or other similar agreement or arrangement entered into for the purpose of reducing the exposure of the Partnership Group to fluctuations in interest rates, the price of hydrocarbons, basis differentials or currency exchange rates in their operations and not for for speculative purposes.

“Holdco” means QA Holdings, LP, a Delaware limited partnership, and any successors thereto.

“Holder” as used in Section 7.12, is defined in Section 7.12(a).

“Incremental Income Taxes” is defined in Section 6.8.

“Indemnified Persons” is defined in Section 7.12(c).

“Indemnitee” means (a) any General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, director, officer, employee, agent, fiduciary or trustee of any Group Member, a General Partner, any Departing General Partner or any of their respective Affiliates, (e) any Person who is or was serving at the request of a General Partner, any Departing General Partner or any of their respective Affiliates as an officer, director, manager, managing member, employee, agent, fiduciary or trustee of another Person owing a fiduciary duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, (f) any Person who controls a General Partner or Departing General Partner and (g) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement because such Person’s service, status or relationship exposes such Person to potential claims, demands, actions, suits or proceedings relating to the Partnership Group’s business and affairs.

“Ineligible Citizen Holder” means a Person whom the General Partner has determined does not constitute an Eligible Citizen Holder and as to whose Partnership Interest the General Partner has become the substitute Limited Partner, pursuant to Section 4.8(a).

“Ineligible Holder” means an Ineligible Citizen Holder or a Rate Ineligible Holder.

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“Initial Common Units” means the Common Units sold in the Initial Offering.

“Initial Limited Partners” means each of QRA2, QRB, QRC and Holdco and the Underwriters, in each case upon being admitted to the Partnership in accordance with Section 10.1.

“Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement, including any Common Units issued pursuant to the exercise of the Over-Allotment Option.

“Initial Unit Price” means (a) with respect to the Common Units and the Subordinated Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

“Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account or for a deferred purchase price in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters in the Initial Offering); and (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements.

“Investment Capital Expenditures” means capital expenditures other than Maintenance Capital Expenditures and Growth Capital Expenditures.

“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

“Limited Partner” means, unless the context otherwise requires, each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as a limited partner of the Partnership.

“Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Class B Units or other Partnership Interests (excluding General Partner Units) or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

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“LTIP” means the Long-Term Incentive Plan of the General Partner, as may be amended, or any equity compensation plan successor thereto.

“Maintenance Capital Expenditures” means cash expenditures (including expenditures for the addition or improvement to or replacement of the capital assets owned by any Group Member or for the acquisition of existing, or the construction or development of new, capital assets) if such expenditures are made to maintain the asset base of the Partnership Group for the long term. Maintenance Capital Expenditures shall not include (a) Expansion Capital Expenditures or (b) Investment Capital Expenditures. Maintenance Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued, other than equity issued on the Closing Date or the Option Closing Date, in each case, to finance the construction or development of a replacement asset and paid during the period beginning on the date that a Group Member enters into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that such replacement asset Commences Commercial Service and the date that such replacement asset is abandoned or disposed of. Debt incurred to pay or equity issued (other than equity issued on the Closing Date or the Option Closing Date), to fund construction or development period interest payments, or such construction or development period distributions on equity, shall also be deemed to be debt or equity, as the case may be, incurred to finance the construction or development of a replacement asset.

“Management Incentive Fee” means a cash management fee paid quarterly pursuant to, and subject to the limitations of, Section 7.4(d).

“Merger Agreement” is defined in Section 14.1.

“Minimum Quarterly Distribution” means $0.4125 per Unit per Quarter (or with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period and the denominator is the total number of days in such quarter), subject to adjustment in accordance with Sections 6.6 and 6.8.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act (or any successor to such Section) and any other securities exchange (whether or not registered with the Commission under Section 6(a) (or successor to such Section) of the Securities Exchange Act) that the General Partner shall designate as a National Securities Exchange for purposes of this Agreement.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any Liabilities either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution.

“Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall include Simulated Gain, but shall not include any items specially allocated under Section 6.1(d) or Section 6.1(e); provided that the determination of the items that have been specially allocated under Section 6.1(d) or Section 6.1(e) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

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“Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gain but shall not include any items specially allocated under Section 6.1(d) or Section 6.1(e); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

“Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable period, the sum, if positive, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5(b)) that are (a) recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) deemed recognized by the Partnership pursuant to Section 5.5(d); provided the items included in the determination of Net Termination Gain shall include Simulated Gain, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d) or Section 6.1(e).

“Net Termination Loss” means, for any taxable period, the sum, if negative, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5(b)) that are (a) recognized by the Partnership (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) deemed recognized by the Partnership pursuant to Section 5.5(d); provided that, items included in the determination of Net Termination Loss shall include Simulated Gain, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d) or Section 6.1(e).

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(b) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Notice of Election to Purchase” is defined in Section 15.1(b).

“OLLC” means QRP Operating, LLC, a Delaware limited liability company, and any successors thereto.

“Omnibus Agreement” means that certain Omnibus Agreement, dated as of the Closing Date, among the Partnership, the General Partner, OLLC, QRA1, QRB, QRC, QAB, QAC, Black Diamond, Holdco and QA Global as such may be amended, supplemented or restated from time to time.

“Operating Expenditures” means all Partnership Group cash expenditures (or the Partnership’s proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including

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taxes, reimbursements of expenses of the General Partner and its Affiliates, payments made in the ordinary course of business under any Hedge Contracts, officer compensation, repayment of Working Capital Borrowings, debt service payments and Estimated Maintenance Capital Expenditures, subject to the following:

(a) repayments of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of Operating Surplus shall not constitute Operating Expenditures when actually repaid;

(b) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures;

(c) Operating Expenditures shall not include (i) Growth Capital Expenditures, (ii) actual Maintenance Capital Expenditures, (iii) Investment Capital Expenditures, (iv) payment of transaction expenses (including taxes) relating to Interim Capital Transactions, (v) distributions to Partners, or (vi) repurchases of Partnership Interests, other than repurchases of Partnership Interests to satisfy obligations under employee benefit plans, or reimbursements of expenses of the General Partner for such purchases. Where capital expenditures are made in part for Maintenance Capital Expenditures and in part for other purposes, the General Partner, with the concurrence of the Conflicts Committee, shall determine the allocation between the amounts paid for each; and

(d) payments made in connection with the initial purchase of a Hedge Contract shall be amortized in equal quarterly installments over the life of such Hedge Contract and payments made in connection with the termination of any Hedge Contract prior to the expiration of its stipulated settlement or termination date shall be amortized in equal quarterly installments over the what would have been the remaining life of such Hedge Contract had it not been so terminated.

“Operating Surplus” means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

(a) the sum of (i) $40.0 million, (ii) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) for the period beginning on the Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions and provided that cash receipts from the termination of any Hedge Contract prior to the expiration of its stipulated settlement or termination date shall be included in equal quarterly installments over the remaining scheduled life of such Hedge Contract, (iii) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings, and (iv) the amount of cash distributions paid on equity issued (other than equity issued on the Closing Date or the Option Closing Date) to finance all or a portion of the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset and paid in respect of the period beginning on the date that the Group Member enters into a binding obligation to commence the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset and ending on the earlier to occur of the date the Capital Improvement or replacement capital asset Commences Commercial Service and the date that it is abandoned or disposed of (equity issued (other than equity issued on the Closing Date or the Option Closing Date) to fund the construction period interest payments on debt incurred, or construction period distributions on equity issued, to finance the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset shall also be deemed to be equity issued to finance the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset for purposes of this clause (iv)); less

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(b) the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period, (ii) the amount of cash reserves established by the General Partner (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) to provide funds for future Operating Expenditures, (iii) all Working Capital Borrowings not repaid within twelve months after having been incurred and (iv) any cash loss realized on the disposition of an Investment Capital Expenditure;

provided, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing, “Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero. Cash receipts from an Investment Capital Expenditure shall be treated as cash receipts only to the extent they are a return on principal, but in no event shall a return of principal be treated as cash receipts.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

“Organizational Limited Partner” means QAP in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

“Outstanding” means, with respect to Partnership Interests, all Partnership Interests that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Interests of any class then Outstanding, all Partnership Interests owned by such Person or Group shall not be entitled to be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Partnership Interests so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Partnership Interests shall not, however, be treated as a separate class of Partnership Interests for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Interests of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided, that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Interests issued by the Partnership if the General Partner shall have notified such Person or Group in writing that such limitation shall not apply.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

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“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means QR Energy, LP, a Delaware limited partnership.

“Partnership Group” means the Partnership and its Subsidiaries treated as a single consolidated entity.

“Partnership Interest” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership), including Common Units, Subordinated Units, Class B Units and General Partner Units.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Sections 1.704-2(b)(2) and 1.704-2(d).

“Percentage Interest” means as of any date of determination (a) as to the General Partner, with respect to the General Partner Interest (calculated based upon a number of General Partner Units), and as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of Outstanding Units and General Partner Units, and (b) as to the holders of other Partnership Interests issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance.

“Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any class of Units held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

“Plan of Conversion” is defined in Section 14.1.

“Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests and (b) when used with respect to Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests.

“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

“QAB” means QAB Carried WI, LP, a Delaware limited partnership, and any successors thereto.

“QAC” means QAC Carried WI, LP, a Delaware limited partnership, and any successors thereto.

“QA Global” means QA Global GP, LLC, a Delaware limited liability company, and any successors thereto.

“QAP” means The Quantum Aspect Partnership, LP, a Delaware limited partnership, and any successors thereto.

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“QRA1” means Quantum Resources A1, LP, a Delaware limited partnership, and any successors thereto.

“QRA1 GP” means QRA1 GP, LP, a Delaware limited partnership, and any successors thereto.

“QRB” means Quantum Resources B, LP, a Delaware limited partnership, and any successors thereto.

“QRC” means Quantum Resources C, LP, a Delaware limited partnership, and any successors thereto.

“QRM” means Quantum Resources Management, LLC, a Delaware limited liability company, and any successors thereto.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership that includes the Closing Date, the portion of such fiscal quarter after the Closing Date.

“Rate Eligible Holder” means a Limited Partner whose federal income tax status would not, in the determination of the General Partner, have the material adverse effect described in Section 4.8(a)(i).

“Rate Eligibility Certification” is defined in Section 4.8(a)(ii).

“Rate Ineligible Holder” is defined in Section 4.8(a)(iii).

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means (a) with respect to Partnership Interests of any class of Partnership Interests for which a Transfer Agent has been appointed, the Person in whose name a Partnership Interest of such class is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.9.

“Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-169664) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders, the excess of (a) the Net Positive Adjustments of such Unitholders as of the end of such period over (b) the sum of such Unitholders’ Share of Additional Book Basis Derivative Items for each prior taxable period and (ii) with respect to the General Partner (as holder of the General Partner Units), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period

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over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Interest for each prior taxable period.

“Required Allocations” means any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vi), Section 6.1(d)(vii), Section 6.1(d)(ix), or Section 6.1(e).

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Services Agreement” means that certain Services Agreement, dated as of the Closing Date, between QRM and the General Partner, as such may be amended, supplemented and restated from time to time.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustments as of that time and (ii) with respect to the General Partner (in respect of the General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such taxable period bears to the Aggregate Remaining Net Positive Adjustment as of that time.

“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property was its adjusted tax basis) and in the manner specified in Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

“Simulated Gain” means the excess, if any, of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

“Simulated Loss” means the excess, if any, of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

“Special Approval” means approval by a majority of the members of the Conflicts Committee.

“Subordinated Unit” means a Partnership Interest representing a fractional part of the Partnership Interests of all Limited Partners and having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term “Subordinated Unit” does not refer to or include a Common Unit or a Class B Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.

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“Subordination Period” means the period commencing on the Closing Date and ending on the first to occur of the following dates:

(a) the later to occur of (i) second anniversary of the Closing Date, and (ii) such time as there are no Cumulative Common Unit Arrearages; and

(b) the date all Outstanding Subordinated Units convert to Common Units pursuant to Section 11.4.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Surviving Business Entity” is defined in Section 14.2(b)(ii).

“Target Distribution” means $0.4744 per Unit per Quarter (or, with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period, and the denominator is the total number of days in such quarter), subject to adjustment in accordance with Sections 6.6 and 6.8.

“Trading Day” means, for the purpose of determining the Current Market Price of any class of Limited Partner Interests, a day on which the principal National Securities Exchange on which such class of Limited Partner Interests is listed or admitted to trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

“transfer” is defined in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the Partnership to act as registrar and transfer agent for any class of Partnership Interests; provided, that if no Transfer Agent is specifically designated for any class of Partnership Interests, the General Partner shall act in such capacity.

“Underwriter” means each Person named as an underwriter in the Underwriting Agreement who purchases Common Units pursuant thereto.

“Underwriting Agreement” means that certain Underwriting Agreement, dated as of December 16, 2010, among the Underwriters, the Partnership, the General Partner and the other parties thereto, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Partnership Interest that is designated as a “Unit” and shall include Common Units, Class B Units and Subordinated Units, but shall not include the General Partner Units.

“Unitholders” means the holders of Units.

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“Unit Majority” means (i) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a class, and at least a majority of the Outstanding Subordinated Units, voting as a class, and (ii) after the end of the Subordination Period, at least a majority of the Outstanding Common Units and Class B Units, if any, voting as a single class.

“Unpaid MQD” is defined in Section 6.1(c)(i)(B).

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

“Unrecovered Initial Unit Price” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

“Unrestricted Person” means (a) each Indemnitee, (b) each Partner, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, a General Partner or any Departing General Partner or any Affiliate of any Group Member, a General Partner or any Departing General Partner and (d) any Person the General Partner designates as an “Unrestricted Person” for purposes of this Agreement.

“U.S. GAAP” means United States generally accepted accounting principles, as in effect from time to time, consistently applied.

“Withdrawal Opinion of Counsel” is defined in Section 11.1(b).

“Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Partners, made pursuant to a credit facility, commercial paper facility or similar financing arrangement; provided, that when incurred it is the intent of the borrower to repay such borrowings within 12 months from sources other than additional Working Capital Borrowings.

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” and words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” and “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

ARTICLE II

ORGANIZATION

Section 2.1 Formation. The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware

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Act and hereby amend and restate the original Agreement of Limited Partnership of QR Energy, LP in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act.

Section 2.2 Name. The name of the Partnership shall be “QR Energy, LP”. The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “L.P.,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 615 S. DuPont Highway, Dover, DE 19901, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be Capitol Services, Inc. The principal office of the Partnership shall be located at 5 Houston Center, 1401 McKinney Street, Suite 2400, Houston, Texas 77010, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate.

Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership of any business.

Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Term. The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7 Title to Partnership Assets. Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any

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portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participating in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners. Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, the reasonableness of which having been determined by the General Partner, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner’s own expense, to obtain:

(i) true and full information regarding the status of the business and financial condition of the Partnership;

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(ii) promptly after its becoming available, a copy of the Partnership’s federal, state and local income tax returns for each year;

(iii) a current list of the name and last known business, residence or mailing address of each Partner;

(iv) a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

(v) true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and that each Partner has agreed to contribute in the future, and the date on which each became a Partner; and

(vi) such other information regarding the affairs of the Partnership as is just and reasonable.

(b) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;

REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates. Notwithstanding anything otherwise to the contrary herein, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by certificates. Certificates that may be issued shall be executed on behalf of the Partnership by the Chairman of the Board, President or any Executive Vice President or Vice President and the Chief Financial Officer or the Secretary or any Assistant Secretary of the General Partner. If a Transfer Agent has been appointed for a class of Partnership Interests, no Certificate for such class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, that if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c), if Common Units are evidenced by Certificates, on or after the date on which Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7, the Record Holders of such Subordinated Units (i) if the Subordinated Units are evidenced by Certificates, may exchange such Certificates for Certificates evidencing Common Units or (ii) if the Subordinated Units are not evidenced by Certificates, shall be issued Certificates evidencing Common Units.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall

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countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Interests as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct, to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after such Limited Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Partnership Interest and (b) bound by this Agreement and shall have the rights and obligations of a Partner hereunder as, and to the extent, provided herein.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall mean a transaction (i) by which the General Partner assigns its General Partner Units to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law

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or otherwise, excludes a pledge, encumbrance, hypothecation or mortgage and includes any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be, to the fullest extent permitted by law, null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner or any Limited Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in the General Partner or Limited Partner and the term “transfer” shall not mean any such disposition.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests.

(b) The Partnership shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions hereof, the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests for which a Transfer Agent has been appointed, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(c) The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.7, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests shall be freely transferable.

(e) The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units, Class B Units and Common Units to one or more Persons.

Section 4.6 Transfer of the General Partner’s General Partner Interest.

(a) Subject to Section 4.6(c) below, prior to December 31, 2020, the General Partner shall not transfer any General Partner Units to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of the General Partner Units to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or

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consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

(b) Subject to Section 4.6(c) below, on or after December 31, 2020, the General Partner may at its option transfer the General Partner Units, in whole or in part, without Unitholder approval.

(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability under the Delaware Act of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest held by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.3, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Restrictions on Transfers.

(a) Except as provided in Section 4.7(d) below, but notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it determines, with the advice of counsel, that such restrictions are necessary or advisable to (i) avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes or (ii) preserve the uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may impose such restrictions by amending this Agreement; provided, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) The transfer of a Subordinated Unit or a Class B Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.7.

(d) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

(i) If, following a request by the General Partner, an Assignee fails to furnish a properly completed Citizenship Certification in a Transfer Application or if, upon receipt of such Citizenship Certification or otherwise, the General Partner determines that such Assignee is

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not an Eligible Citizen Holder, the Limited Partner Interests owned by such Assignee shall be subject to redemption in accordance with the provisions of Section 4.9.

(ii) The General Partner may request any Limited Partner or Assignee to furnish to the General Partner, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Limited Partner or Assignee is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner may request. If a Limited Partner or Assignee fails to furnish to the General Partner within the aforementioned 30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the General Partner determines that a Limited Partner or Assignee is not an Eligible Citizen Holder, the Limited Partner Interests owned by such Limited Partner or Assignee shall be subject to redemption in accordance with the provisions of Section 4.9. In addition, the General Partner may require that the status of any such Limited Partner or Assignee be changed to that of an Ineligible Citizen Holder and, thereupon, such Ineligible Citizen Holder shall cease to be a Partner and shall have no voting rights (whether arising hereunder, under the Delaware Act, at law, in equity or otherwise) in respect of his Limited Partner Interests or the Partnership. The General Partner shall be substituted for such Ineligible Citizen Holder as the Limited Partner or Assignee in respect of such Ineligible Citizen Holder’s Limited Partner Interests and shall vote such Limited Partner Interests in accordance with Section 4.8(c).

Section 4.8 Eligibility Certificates; Ineligible Holders

(a)(i) If at any time the General Partner determines, with the advice of counsel, that the Partnership’s status other than as an association taxable as a corporation for U.S. federal income tax purposes or the failure of the Partnership otherwise to be subject to an entity-level tax for U.S. federal, state or local income tax purposes, coupled with the tax status (or lack of proof of the U.S. federal income tax status) of one or more Limited Partners, has or will reasonably likely have a material adverse effect on the maximum applicable rate that can be charged to customers by Subsidiaries of the Partnership, then the General Partner may adopt such amendments to this Agreement as it determines to be necessary or advisable to obtain such proof of the federal income tax status of the Limited Partners and, to the extent relevant, their beneficial owners, as the General Partner determines to be necessary to establish those Limited Partners whose U.S. federal income tax status does not or would not have a material adverse effect on the maximum applicable rate that can be charged to customers by Subsidiaries of the Partnership.

(ii) Such amendments may include provisions requiring all Limited Partners to certify as to their (and their beneficial owners’) status as Rate Eligible Holders upon demand and on a regular basis, as determined by the General Partner, and may require transferees of Units to so certify prior to being admitted to the Partnership as a Substituted Limited Partner (any such required certificate, a “Rate Eligibility Certification”).

(iii) Such amendments may provide that any Limited Partner who fails to furnish to the General Partner within a reasonable period requested proof of its (and its beneficial owners’) status as a Rate Eligible Holder or if upon receipt of such Rate Eligibility Certification or other requested information the General Partner determines that a Limited Partner is not a Rate Eligible Holder (such a Limited Partner, a “Rate Ineligible Holder”), the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.9. In addition, the General Partner shall be substituted for all

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Limited Partners that are Rate Ineligible Holder as the Limited Partner in respect of the Rate Ineligible Holder’s Limited Partner Interests.

(b) The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Ineligible Holders, distribute the votes in the same ratios as the votes of Limited Partners (including the General Partner and its Affiliates) in respect of Limited Partner Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.

(c) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Holder of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

(d) At any time after he can and does certify that he has become an Eligible Holder, an Ineligible Holder may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Ineligible Holder not redeemed pursuant to Section 4.9, such Ineligible Holder be admitted as a Substituted Limited Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as a Substituted Limited Partner and shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the Limited Partner in respect of the Ineligible Holder’s Limited Partner Interests.

Section 4.9 Redemption of Partnership Interests of Ineligible Holders.

(a) If at any time a Limited Partner fails to furnish an Eligibility Certification or other information requested within the time period specified in Section 4.8(a) or in amendments adopted pursuant to Section 4.8(b) or in a Transfer Application, or if upon receipt of such Eligibility Certification, Transfer Application or other information, the General Partner determines, with the advice of counsel, that a Limited Partner is an Ineligible Holder, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is not an Ineligible Holder or has transferred his Limited Partner Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certification, Transfer Application or other information, as the case may be, to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash

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or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) The Limited Partner or his duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Limited Partner at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.9 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee of a Person determined to be other than an Eligible Holder.

(c) Nothing in this Section 4.9 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that he is an Eligible Holder. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Organizational Contributions. In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $1.00 in exchange for a General Partner Interest equal to a 0.1% Percentage Interest and has been admitted as the General Partner of the Partnership. The Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $999.00 in exchange for a Limited Partner Interest equal to a 99.9% Percentage Interest and has been admitted as a Limited Partner of the Partnership. As of the Closing Date, and effective with the admission of another Limited Partner to the Partnership, the interest of the Organizational Limited Partner shall be redeemed as provided in the Contribution Agreement and the initial Capital Contributions of (i) the Organizational Limited Partner and (ii) the General Partner shall thereupon be refunded. Ninety-nine and 9/10ths percent of any interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated and distributed to the Organizational Limited Partner, and the balance thereof shall be allocated and distributed to the General Partner.

Section 5.2 Contributions by the General Partner and its Affiliates.

(a) On the Closing Date and pursuant to the Contribution Agreement: (i) the General Partner shall contribute to the Partnership, as a Capital Contribution, the GP Contribution (as defined in the Contribution Agreement) in exchange for 35,729 General Partner Units, representing a continuation of its General Partner Interest with a 0.1% Percentage Interest (after giving effect to any exercise of the Over-Allotment Option and the Deferred Issuance and Distribution), subject to all of the rights, privileges and duties of the General Partner under this Agreement and (ii) the Fund Group shall contribute to the Partnership, as a Capital Contribution, the Holdings

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Contribution (as defined in the Contribution Agreement) in exchange for 11,297,737 Common Units, 7,145,866 Subordinated Units, the right to receive $300.0 million in reimbursement for certain capital expenditures and the right to receive the Deferred Issuance and Distribution.

(b) Upon the issuance of any additional Limited Partner Interests by the Partnership (other than the Common Units issued in the Initial Offering, the Common Units issued pursuant to the Over-Allotment Option or the Deferred Issuance and Distribution, the Common Units issued upon conversion of the Subordinated Units or Class B Units and any Class B Units issued pursuant to Section 5.11), the General Partner may, in exchange for a proportionate number of General Partner Units, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest by (B) 100 less the General Partner’s Percentage Interest times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests. Except as set forth in Section 12.8, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.3 Contributions by Initial Limited Partners.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(b) Upon the exercise, if any, of the Over-Allotment Option, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(c) No Limited Partner will be required to make any additional Capital Contribution to the Partnership pursuant to this Agreement.

Section 5.4 Interest and Withdrawal. No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon liquidation of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.5 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including Simulated Gain and income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

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(b) For purposes of computing the amount of any item of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss that is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement) of all property owned by (x) any other Group Member that is classified as a partnership for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equity holder.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction Simulated Depletion, Simulated Gain and Simulated Loss shall be made without regard to any election under Section 754 of the Code that may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery, amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery, amortization or Simulated Depletion, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined under the rules prescribed by Treasury Regulation Section 1.704-3(d)(2) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

(vi) The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values. The amount of any such adjustment shall be treated for purposes hereof as an item of loss (if the adjustment increases the Carrying

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Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership).

(c) (i) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(ii)

(A) Subject to Section 6.7(c), immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.5(c)(ii)(A) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (1) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (2) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Subordinated Units or converted Subordinated Units. Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Subordinated Units or retained converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (2) hereinabove, and the transferee’s Capital Account established with respect to the transferred Subordinated Units or transferred converted Subordinated Units will have a balance equal to the amount allocated under clause (1) hereinabove.

(B) Subject to Section 6.7(c), immediately prior to the transfer of a Class B Unit or of a Class B Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.5(c)(ii)(B) apply), the Capital Account maintained for such Person with respect to its Class B Units or converted Class B Units will (1) first, be allocated to the Class B Units or converted Class B Units to be transferred in an amount equal to the product of (x) the number of such Class B Units or converted Class B Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (2) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Class B Units or converted Class B Units. Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Class B Units or retained converted Class B Units, if any, will have a balance equal to the amount allocated under clause (2) hereinabove, and the transferee’s Capital Account established with respect to the transferred Class B Units or transferred converted Class B Units will have a balance equal to the amount allocated under clause (1) hereinabove

(d) (i) Consistent with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), upon an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services, or the conversion of the Combined Interest to Common Units pursuant to Section 11.3(b), the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated among the Partners at such time

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pursuant to Section 6.1(c) in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated; provided, that in the event of an issuance of Partnership Interests for a de minimis amount of cash or Contributed Property, or in the event of an issuance of a de minimis amount of Partnership Interests as consideration for the provision of services, the General Partner may determine that such adjustments are unnecessary for the proper administration of the Partnership. In determining such Unrealized Gain or Unrealized Loss, the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt. In making its determination of the fair market values of individual properties, the General Partner may determine that it is appropriate to first determine an aggregate value for the Partnership, based on the current trading price of the Common Units, and taking fully into account the fair market value of the Partnership Interests of all Partners at such time, and then allocate such aggregate value among the individual properties of the Partnership (in such manner as it determines appropriate).

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, and any such Unrealized Gain or Unrealized Loss shall be treated, for purposes of maintaining Capital Accounts, as if it had been recognized on an actual sale of each such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated among the Partners, at such time, pursuant to Section 6.1(c) in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate fair market value of all Partnership property (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined by the Liquidator using such method of valuation as it may adopt.

Section 5.6 Issuances of Additional Partnership Interests.

(a) The Partnership may issue additional Partnership Interests and options, rights, warrants and appreciation rights relating to the Partnership Interests (including as described in Section 7.4(c)) for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Interest authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Interests), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Interest (including sinking fund provisions); (v) whether such Partnership Interest is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership

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Interest will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Interest; and (viii) the right, if any, of each such Partnership Interest to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Interest.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Interests and options, rights, warrants and appreciation rights relating to Partnership Interests pursuant to this Section 5.6, including Common Units issued in connection with the Deferred Issuance and Distribution, (ii) the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, (iii) the issuance of Class B Units pursuant to Section 5.11, (iv) reflecting admission of such additional Limited Partners in the books and records of the Partnership as the Record Holder of such Limited Partner Interest and (v) all additional issuances of Partnership Interests. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Interests being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Interests or in connection with the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Interests are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

Section 5.7 Conversion of Subordinated Units.

(a) All of the Subordinated Units shall convert into Common Units on a one-for-one basis on the first Business Day following the end of the Subordination Period.

(b) The Subordinated Units may also convert into Common Units as set forth in, and pursuant to the terms of, Section 11.4.

Section 5.8 Limited Preemptive Right. Except as provided in this Section 5.8 and in Section 5.2 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Interest, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Interests from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Interests to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Interests.

Section 5.9 Splits and Combinations.

(a) Subject to Section 5.9(d), Section 6.6 and Section 6.8 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Interests to all Record Holders or may effect a subdivision or combination of Partnership Interests so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units are proportionately adjusted retroactive to the beginning of the Partnership.

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(b) Whenever such a distribution, subdivision or combination of Partnership Interests is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Interests to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates to the Record Holders of Partnership Interests as of the applicable Record Date representing the new number of Partnership Interests held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Interests Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of Section 5.6(d) and this Section 5.9(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.10 Fully Paid and Non-Assessable Nature of Limited Partner Interests. All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 or 17-804 of the Delaware Act.

Section 5.11 Issuance of Class B Units in Connection with Conversion of Management Incentive Fee.

(a) Subject to the provisions of this Section 5.11, the General Partner shall have the right, at any time after the end of the Subordination Period (or in connection with the final Quarter of the Subordination Period) when the General Partner has received all or any portion of the Management Incentive Fee in respect of each of the three full consecutive Quarters immediately preceding a Quarter in respect of which all or a portion of the Management Incentive Fee is then due (or will become due following payment of the distribution in respect of such Quarter) (a “Conversion Quarter”), to make a Conversion Election to convert into Class B Units the Applicable Conversion Percentage of the Management Incentive Fee in respect of a Conversion Quarter.

(b) The number of Class B Units to which the General Partner will become entitled to receive will be equal to that number of Common Units (the “Aggregate Quantity of Class B Units”) derived by dividing (i) the product resulting from the multiplication of (X) the Applicable Conversion Percentage; by (Y) the average (1) of the Management Incentive Fee paid to the General Partner in the Quarter immediately preceding the Conversion Quarter and (2) the Management Incentive Fee payable in respect of the Conversion Quarter by (ii) the cash distribution made by the Partnership in respect of each Common Unit in respect of the Conversion Quarter.

(c) To exercise the right specified in Section 5.11(a), the General Partner shall deliver a written notice of its Conversion Election (the “Conversion Election Notice”) to the Partnership.

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Any Conversion Election must be made before payment of the Management Incentive Fee in respect of the Conversion Quarter and will be effective as of the first day of the Conversion Quarter in which such Conversion Election is made and, if the Class B Units are issued after the record date for the distribution in respect of the Conversion Quarter in which such Conversion Election is made, such Class B Units shall be entitled to the same distribution as they would have been entitled had they been outstanding since such first day.

(d) The General Partner will be entitled to receive the Aggregate Quantity of Class B Units on the fifteenth Business Day after receipt by the Partnership of the Conversion Election Notice; provided, that the issuance of Class B Units to the General Partner shall not occur prior to the approval of the listing or admission for trading of the Common Units into which the Class B Units are convertible pursuant to Section 5.11(f) by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.

(e) If the principal National Securities Exchange upon which the Common Units are then traded has not approved the listing or admission for trading of the Common Units into which the Class B Units are convertible pursuant to Section 5.11(f) on or before the 30th calendar day following the Partnership’s receipt of the Conversion Election Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the General Partner shall have the right to either rescind the Conversion Election or elect to receive other Partnership Securities having such terms as the General Partner may approve, with the approval of the Conflicts Committee, that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of Class B Units would have had at the time of the Partnership’s receipt of the Conversion Election Notice, as determined by the General Partner, and (ii) for the subsequent conversion of such Partnership Securities into Common Units within not more than 12 months following the Partnership’s receipt of the Conversion Election Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the General Partner.

(f) Following a Conversion Election the General Partner will not be permitted to make another Conversion Election pursuant to Section 5.1(a) until after (i) the completion of the fourth full Quarter after the Quarter in respect of which the previous Conversion Election was made and (ii) the Gross Management Incentive Fee Base has increased to 115% of the Gross Management Incentive Fee Base calculated as of the immediately preceding Conversion Date.

(g) Any holder of Class B Units shall have the right to elect, by giving written notice to the General Partner, to convert all or a portion of the Class B Units held by such holder, at any time, into Common Units on a one-for-one basis, such conversion to be effective on the second Business Day following the General Partner’s receipt of such written notice.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with Section 5.5(b)) for each taxable period shall be allocated among the Partners as provided herein below.

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(a) Net Income. Net Income for each taxable period and all items of income, gain, loss, deduction, and Simulated Gain taken into account in computing Net Income for such taxable period shall be allocated as follows:

(i) First, to the General Partner until the aggregate of the Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) and the Net Termination Gain allocated to the General Partner pursuant to Section 6.1(c)(i)(A) or Section 6.1(c)(iv)(A) for the current and all previous taxable periods is equal to the aggregate of the Net Loss allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods and the Net Termination Loss allocated to the General Partner pursuant to Section 6.1(c)(ii)(E) or Section 6.1(c)(iii)(B) for the current and all previous taxable periods; and

(ii) The balance, if any, to the General Partner and all Unitholders, Pro Rata.

provided, that Unitholders holding Class B Units will not be allocated any items of Net Income pursuant to this Section 6.1(a) with respect to their Class B Units until the Adjusted Capital Account of each Common Unit and each Class B Unit or comparable fraction thereof are equal.

(b) Net Loss. Net Loss for each taxable period and all items of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Loss for such taxable period shall be allocated as follows:

(i) First, to the General Partner and the Unitholders, Pro Rata; provided, that Net Loss shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account); and

(ii) The balance, if any, 100% to the General Partner.

provided, that Unitholders holding Class B Units will not be allocated any items of Net Loss pursuant to this Section 6.1(b) with respect to their Class B Units until the Adjusted Capital Account of each Common Unit and each Class B Unit are equal.

(c) Net Termination Gains and Losses. Net Termination Gain or Net Termination Loss (including a pro rata part of each item of income, gain, loss, deduction, and Simulated Gain taken into account in computing Net Termination Gain or Net Termination Loss) for such taxable period shall be allocated in the manner set forth in this Section 6.1(c). All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 and Section 6.5 have been made; provided, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(i) Except as provided in Section 6.1(c)(iv), Net Termination Gain (including a pro rata part of each item of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Termination Gain) shall be allocated:

(A) First, to the General Partner until the aggregate of the Net Termination Gain allocated to the General Partner pursuant to this Section 6.1(c)(i)(A) or Section 6.1(c)(iv)(A) and the Net Income allocated to the General Partner pursuant to Section 6.1(a)(i) for the current and all previous taxable periods is equal to the aggregate of the Net Loss allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods and the Net Termination Loss allocated to the General

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Partner pursuant to Section 6.1(c)(ii)(E) or Section 6.1(c)(iii)(B) for all previous taxable periods;

(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units and Class B Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter referred to as the “Unpaid MQD”) and (3) any then existing Cumulative Common Unit Arrearage;

(C) Third, if the Adjusted Capital Account of a Common Unit and a Class B Unit (or converted Class B Unit) are not identical, (x) to all Unitholders holding the class of Units with the lower Adjusted Capital Account, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, and (y) to the General Partner in accordance with its Percentage Interest, until the Adjusted Capital Account of each Common Unit and each Class B Unit (or converted Class B Unit) are equal;

(D) Fourth, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit into a Common Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable period (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter; and

(E) The balance, if any, 100% to the General Partner and all Unitholders, Pro Rata.

(ii) Except as otherwise provided by Section 6.1(c)(iii), Net Termination Loss (including a pro rata part of each item of income, gain, loss, deduction and Simulated Gain taken into account in computing Net Termination Loss) shall be allocated:

(A) First, if Subordinated Units remain Outstanding, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less General Partner’s Percentage Interest, until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

(B) Second, if the Adjusted Capital Account of a Common Unit and a Class B Unit (or converted Class B Unit) are not identical, to (i) the Unitholders holding the class of Units with the higher Adjusted Capital Account, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest and (ii) to the General Partner, in accordance with its Percentage Interests, until the Adjusted Capital Account of each Common Unit and each Class B Unit (or converted Class B Unit) are equal;

(C) Third, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units and Class B Units, Pro Rata, a percentage equal to 100% less General Partner’s Percentage Interest, until the Capital

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Account in respect of each Common Unit and Class B Unit then Outstanding has been reduced to zero;

(D) Fourth, to the General Partner and the Unitholders, Pro Rata; provided, that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(ii)(D) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account (or increase any existing deficit in its Adjusted Capital Account); and

(E) The balance, if any, 100% to the General Partner.

(iii) Any Net Termination Loss deemed recognized pursuant to Section 5.5(d) prior to the Liquidation Date shall be allocated:

(A) First, to the General Partner and the Unitholders, Pro Rata; provided, that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(iii)(A) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit in its Adjusted Capital Account); and

(B) The balance, if any, to the General Partner.

(iv) If a Net Termination Loss has been allocated pursuant to Section 6.1(c)(iii), any subsequent Net Termination Gain deemed recognized pursuant to Section 5.5(d) prior to a Liquidation Date shall be allocated:

(A) First, to the General Partner until the aggregate Net Termination Gain allocated to the General Partner pursuant to this Section 6.1(c)(iv)(A) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(B);

(B) Second, to the General Partner and the Unitholders, Pro Rata, until the aggregate Net Termination Gain allocated pursuant to this Section 6.1(c)(iv)(A) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(A); and

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain or Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse

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Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain or Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations.

(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) with respect to a Unit exceeds the amount of cash or the Net Agreed Value of property distributed with respect to another Unit (the amount of the excess, an “Excess Distribution” and the Unit with respect to which the greater distribution is paid, an “Excess Distribution Unit”), then (1) there shall be allocated gross income and gain to each Unitholder receiving an Excess Distribution with respect to the Excess Distribution Unit until the aggregate amount of such items allocated with respect to such Excess Distribution Unit pursuant to this Section 6.1(d)(iii)(A) for the current taxable period and all previous taxable periods is equal to the amount of the Excess Distribution; and (2) the General Partner shall be allocated gross income and gain with respect to each such Excess Distribution in an amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time when the Excess Distribution occurs by (y) a percentage equal to 100% less the General Partner’s Percentage Interest at the time when the Excess Distribution occurs, times (bb) the amount allocated in clause (1) above with respect to such Excess Distribution.

(B) After the application of Section 6.1(d)(iii)(A), the remaining items of Partnership gross income or gain for the taxable period, if any, shall be allocated (1) to the Unitholders holding Class B Units, Pro Rata, until the aggregate amount of such items allocated to the holders of Class B Units pursuant to this Section 6.1(d)(iii)(B) for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions of Available Cash made to the holders of Class B Units during the periods such holders of Class B Units are not allocated any items of Net Income or Net Loss pursuant to Section 6.1(a) or Section 6.1(b) with respect to their Class B Units; and (2) to the General Partner an amount equal to the product of (aa) an amount equal to the quotient determined by dividing (x) the General Partner’s Percentage Interest by (y) the sum of 100 less the General Partner’s Percentage Interest times (bb) the sum of the amounts allocated in clause (1) above.

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created

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by such adjustments, allocations or distributions as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(iv) shall be made only if and to the extent that such Partner would have a deficit balance in its Adjusted Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(iv) were not in this Agreement.

(v) Gross Income Allocation. In the event any Partner has a deficit balance in its Capital Account at the end of any taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of the Partnership’s gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if Section 6.1(d)(iv) and this Section 6.1(d)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners Pro Rata. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners Pro Rata.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain, loss, Simulated Gain or Simulated Loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Economic Uniformity; Changes in Law.

(A) At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership gross income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to

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each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period (“Final Subordinated Units”) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount that after taking into account the other allocations of income, gain, loss and deduction to be made with respect to such taxable period will equal the product of (A) the number of Final Subordinated Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.

(B) With respect to an event triggering an adjustment to the Carrying Value of Partnership property pursuant to Section 5.5(d) during any taxable period of the Partnership ending upon, or after, the issuance of Class B Units pursuant to Section 5.11, after the application of Section 6.1(d)(x)(A), any Unrealized Gains and Unrealized Losses shall be allocated among the Partners in a manner that to the nearest extent possible results in the Capital Accounts maintained with respect to such Class B Units issued pursuant to Section 5.11 equaling the product of (A) the Aggregate Quantity of Class B Units and (B) the Per Unit Capital Amount for an Initial Common Unit.

(C) With respect to any taxable period during which a Class B Unit is transferred to any Person who is not an Affiliate of the transferor, all or a portion of the remaining items of Partnership gross income or gain for such taxable period shall be allocated 100% to the transferor Partner of such transferred Class B Unit until such transferor Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such transferred Class B Unit to an amount equal to the Per Unit Capital Amount for an Initial Common Unit.

(D) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(d)(x)(D) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Outstanding Limited Partner Interests, and if such allocations are consistent with the principles of Section 704 of the Code.

(xi) Curative Allocation.

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(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss, deduction Simulated Depletion, Simulated Gain and Simulated Loss allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1 and Simulated Depletion and Simulated Loss had been included in the definition of Net Income, Net Loss, Net Termination Gain and Net Termination Loss. In exercising its discretion under this Section 6.1(d)(xi)(A), the General Partner may take into account future Required Allocations that, although not yet made, are likely to offset other Required Allocations previously made. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii) Corrective and Other Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) Except as provided in Section 6.1(d)(xii)(B), in the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof), the General Partner shall allocate such Additional Book Basis Derivative Items to (1) the General Partner to the same extent that the Unrealized Gain or Unrealized Loss giving rise to such Additional Book Basis Derivative Items was allocated to it pursuant to Section 5.5(d) and (2) all Unitholders, Pro Rata, to the extent that the Unrealized Gain or Unrealized Loss giving rise to such Additional Book Basis Derivative Items was allocated to any Unitholders pursuant to Section 5.5(d).

(B) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof or an allocation of Net Termination Gain or Net Termination Loss pursuant to Section 6.1(c) hereof) as a result of a sale or other taxable disposition of any Partnership asset that is an Adjusted Property (“Disposed of Adjusted Property”), the General Partner shall allocate (1) additional items of gross income and gain (aa) away from the General Partner and (bb) to the Unitholders, or (2) additional items of deduction and loss (aa) away from the Unitholders and (bb) to the General Partner, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. Any allocation made pursuant to this Section 6.1(d)(xii)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

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(C) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balances of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

(D) For purposes of this Section 6.1(d)(xii), the Unitholders shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders under this Agreement. In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii). Without limiting the foregoing, if an Adjusted Property is contributed by the Partnership to another entity classified as a partnership for federal income tax purposes (the “lower tier partnership”), the General Partner may make allocations similar to those described in Sections 6.1(d)(xii)(A) — (C) to the extent the General Partner determines such allocations are necessary to account for the Partnership’s allocable share of income, gain, loss and deduction of the lower tier partnership that relate to the contributed Adjusted Property in a manner that is consistent with the purpose of this Section 6.1(d)(xii).

(xiii) Special Curative Allocation in Event of Liquidation Prior to End of Subordination Period. Notwithstanding any other provision of this Section 6.1 (other than the Required Allocations), if the Liquidation Date occurs prior to the conversion of the last Outstanding Subordinated Unit, then items of income, gain, loss and deduction for the taxable period that includes the Liquidation Date (and, if necessary, items arising in previous taxable periods to the extent the General Partner determines such items may be so allocated), shall be specially allocated among the Partners in the manner determined appropriate by the General Partner so as to cause, to the maximum extent possible, the Capital Account in respect of each Common Unit to equal the amount such Capital Account would have been if all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable.

(e) Simulated Depletion and Simulated Loss.

(i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(k), Simulated Depletion with respect to each oil and gas property shall be allocated among the General Partner and the Unitholders Pro Rata, provided, that Unitholders holding Class B Units will not be allocated any Simulated Depletion or Simulated Loss pursuant to this Section 6.2(e) with respect to their Class B Units until the Adjusted Capital Account of each Common Unit and each Class B Unit are equal.

(ii) Simulated Loss with respect to the disposition of an oil and gas property shall be allocated among the Partners in proportion to their allocable share of total amount realized from such disposition under Section 6.2(c)(i).

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Section 6.2 Allocations for Tax Purposes.

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

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Partners rather than by the Partnership in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Partners Pro Rata.

Each Partner shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Partnership.

(c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Partner on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Partnership’s allocable share of the “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Partners as follows”

(i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Partners in the same proportion as the depletable basis of such property was allocated to the Partners pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii));

(ii) second, the remainder of such amount realized, if any, to the Partners so that, to the maximum extent possible, the amount realized allocated to each Partner under this Section 6.2(c)(ii) will equal such Partner’s share of the Simulated Gain recognized by the Partnership from such sale or disposition.

(iii) The Partners recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Partners to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d).

(d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than oil and gas properties pursuant to Section 6.2(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners in the manner provided under Section 704(c) of the Code, and the Treasury Regulations promulgated under Section 704(b) and 704(c) of the Code, as determined appropriate by the General Partner (taking into account the General Partner’s discretion under Section 6.1(d)(x)(D)); provided, that the General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) in all events.

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(e) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(f) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(g) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(h) Each item of Partnership income, gain, loss and deduction shall, for federal income tax purposes, be determined for each taxable period and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Over-Allotment Option is exercised in full or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the next succeeding month; and provided further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income, gain, loss or deduction as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the month in which such item is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(i) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

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Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 45 days following the end of each Quarter commencing with the Quarter ending on December 31, 2010, an amount equal to 100% of Available Cash with respect to such Quarter shall be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be “Capital Surplus.” All distributions required to be made under this Agreement shall be subject to Sections 17-607 and 17-804 of the Delaware Act.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all cash received during or after the Quarter in which the Liquidation Date occurs, other than from Working Capital Borrowings, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through any Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4 Distributions of Available Cash from Operating Surplus.

(a) During Subordination Period. Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or 6.5 shall be distributed as follows, except as otherwise contemplated by Section 5.6(b) in respect of other Partnership Interests issued pursuant thereto:

(i) First, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;

(iii) Third, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter; and

(iv) Thereafter, to the General Partner and all Unitholders, Pro Rata;

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provided, if the Minimum Quarterly Distribution has been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(iv).

(b) After Subordination Period. Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall be distributed to the General Partner and all Unitholders, Pro Rata.

Section 6.5 Distributions of Available Cash from Capital Surplus. Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the General Partner and the Unitholders, Pro Rata, until the Minimum Quarterly Distribution has been reduced to zero pursuant to the second sentence of Section 6.6(a). Available Cash that is deemed to be Capital Surplus shall then be distributed (a) to the General Partner in accordance with its Percentage Interest and (b) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4(b).

Section 6.6 Adjustment of Minimum Quarterly Distribution and Target Distribution.

(a) The Minimum Quarterly Distribution, Target Distribution, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Interests in accordance with Section 5.9. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution and Target Distribution shall be reduced in the same proportion that the distribution had to the fair market value of the Common Units immediately prior to the announcement of the distribution. If the Common Units are publicly traded on a National Securities Exchange, the fair market value will be the Current Market Price before the ex-dividend date. If the Common Units are not publicly traded, the fair market value will be determined by the Board of Directors.

(b) The Minimum Quarterly Distribution and Target Distribution shall also be subject to adjustment pursuant to Section 6.8.

Section 6.7 Special Provisions Relating to the Holders of Subordinated Units and Class B Units.

(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided further, that such converted Subordinated Units shall remain subject to the provisions of Sections 5.5(c)(ii), 6.1(d)(x), 6.7(b) and 6.7(c).

(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to

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the retained Subordinated Units or retained converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(A)(2).

(c) A Unitholder holding a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 shall not be issued a Common Unit Certificate pursuant to Section 4.1, if the Common Units are evidenced by Certificates, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Sections 5.5(c)(ii) and 6.1(d)(x); provided, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

(d) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Class B Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, that immediately upon the conversion of Class B Units into Common Units pursuant to Section 5.11(g), the Unitholder holding a Class B Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder with respect to such converted Class B Units, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided further, that such converted Class B Units shall remain subject to the provisions of Sections 6.1(a), 6.1(b), 6.1(d)(iii), 6.1(d)(x), 6.7(b) and 6.7(f).

(e) A Unitholder shall not be permitted to transfer a Class B Unit or a Class B Unit that has converted into a Common Unit pursuant to Section 5.11(g) (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained Class B Units or retained converted Class B Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

(f) A Unitholder holding a Common Unit that has resulted from the conversion of a Class B Unit pursuant to Section 5.11(g) shall not be issued a Common Unit Certificate pursuant to Section 4.1, if the Common Units are evidenced by Certificates, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(f), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Sections 6.1(d)(x), 6.7(b) and 6.7(f); provided, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

Section 6.8 Entity-Level Taxation. If legislation is enacted or the official interpretation of existing legislation is modified by a governmental authority, which after giving effect to such enactment or modification, results in a Group Member becoming subject to federal, state or local or non-U.S. income or withholding taxes in excess of the amount of such taxes due from the Group Member prior to such enactment or modification (including, for the avoidance of doubt, any increase in the rate of such

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taxation applicable to the Group Member), then the General Partner may, in its sole discretion, reduce the Minimum Quarterly Distribution and Target Distribution by the amount of income or withholding taxes that are payable by reason of any such new legislation or interpretation (the “Incremental Income Taxes”), or any portion thereof selected by the General Partner, in the manner provided in this Section 6.8. If the General Partner elects to reduce the Minimum Quarterly Distribution and Target Distribution for any Quarter with respect to all or a portion of any Incremental Income Taxes, the General Partner shall estimate for such Quarter the Partnership Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount”) for all (or the relevant portion of) such Incremental Income Taxes; provided, that any difference between such estimate and the actual liability for Incremental Income Taxes (or the relevant portion thereof) for such Quarter may, to the extent determined by the General Partner, be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Minimum Quarterly Distribution and Target Distribution shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.8 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible or exchangeable into Partnership Interests, and the incurring of any other obligations;

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

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 or Article XIV);

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(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of Partnership cash;

(vii) the selection, employment, retention and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors of the General Partner or the Partnership Group and the determination of their compensation and other terms of employment or hiring;

(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

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

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.7);

(xiii) the purchase, sale or other acquisition or disposition of Partnership Interests, or the issuance of options, rights, warrants and appreciation rights relating to Partnership Interests;

(xiv) the undertaking of any action in connection with the Partnership’s participation in the management of any Group Member; and

(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and each other Person who may acquire an interest in Partnership Interests or is otherwise bound by this

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Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement, the Underwriting Agreement, the Contribution Agreement, the Services Agreement, the Omnibus Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement (in each case other than this Agreement, without giving effect to any amendments, supplements or restatements after the date hereof); (ii) agrees that the General Partner (on its own or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Interests or is otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

Section 7.2 Certificate of Limited Partnership. The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3 Restrictions on the General Partner’s Authority. Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions without the approval of holders of a Unit Majority; provided, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.4 Reimbursement of the General Partner; Management Incentive Fee.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation, employment benefits and other amounts paid to any Person, including Affiliates of the General

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Partner, to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group, including for amounts paid by the General Partner under the Services Agreement), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the General Partner or the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership benefit plans, programs and practices (including plans, programs and practices involving the issuance of Partnership Interests or options to purchase or rights, warrants or appreciation rights or phantom or tracking interests relating to Partnership Interests), or cause the Partnership to issue Partnership Interests in connection with, or pursuant to, any benefit plan, program or practice maintained or sponsored by the General Partner or any of its Affiliates, in each case for the benefit of employees and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Interests that the General Partner or such Affiliates are obligated to provide to any employees and directors pursuant to any such benefit plans, programs or practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Interests purchased by the General Partner or such Affiliates, from the Partnership, to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any benefit plans, programs or practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

(d) The Partnership shall pay the General Partner a Management Incentive Fee in respect of each Quarter for which the Partnership has made a distribution of Available Cash from Operating Surplus in respect of each outstanding Unit in an amount equal to or greater than Target Distribution. The amount of the Management Incentive Fee for each such Quarter shall equal the product of (a) 0.25% and (b) the Adjusted Management Incentive Fee Base as of the applicable Calculation Date (which shall be the most recent December 31, in the case of Quarters ending March 31 or June 30, or the most recent June 30, in the case of Quarters ending September 30 or December 31); provided, that the Management Incentive Fee, if any, payable in respect of the quarter in which the Closing Date occurs shall be prorated based on the number of days in such quarter after the Closing Date. The Management Incentive Fee in respect of each Quarter shall be paid promptly following the distribution of Available Cash by the Partnership in respect of such Quarter. The amount of the Management Incentive Fee otherwise payable in respect of any Quarter will be reduced to the extent that the payment of such Management Incentive Fee would have caused Adjusted Operating Surplus for such Quarter to be less than 100% of the amount of Available Cash distributed in respect of such Quarter on all Outstanding Common Units, Subordinated Units, Class B Units and General Partner Units if such Management Incentive Fee had been paid during such Quarter. Any portion of the Management Incentive Fee not paid as a result of the foregoing limitations shall not accrue or be payable in future quarters.

(e) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of

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any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.

Section 7.5 Outside Activities.

(a) The General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a Limited Partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement or (B) the acquiring, owning or disposing of debt securities or equity interests in any Group Member.

(b) Except to the extent otherwise set forth in the Omnibus Agreement, each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise, to any Group Member or any Partner. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Unrestricted Person.

(c) Subject to the terms of Sections 7.5(a) and (b), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of the General Partner or any other Unrestricted Person for the Unrestricted Persons (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Unrestricted Persons shall have no obligation hereunder or as a result of any duty otherwise existing at law, in equity or otherwise, to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership; provided, such Unrestricted Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.

(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Interests in addition to those acquired on the Closing Date and, except as otherwise provided in

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this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units and/or other Partnership Interests acquired by them. The term “Affiliates” when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e) Notwithstanding anything to the contrary in this Agreement, to the extent that any provision of this Agreement purports or is interpreted to have the effect of restricting the fiduciary duties that might otherwise, as a result of Delaware or other applicable law, be owed by the General Partner to the Partnership and the Limited Partners, or to constitute a waiver or consent by the Limited Partners to any such restriction, such provisions shall be deemed to have been approved by the Partners.

Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may, but shall be under no obligation to, lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty hereunder or otherwise existing at law, in equity or otherwise, of the General Partner or its Affiliates to the Partnership or the Limited Partners by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner’s Percentage Interest of the total amount distributed to all Partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee and acting (or refraining to act) in such capacity; provided, that the Indemnitee shall not be indemnified and held harmless pursuant to this Agreement if there has been a final and non-appealable judgment entered by a court of competent

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jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Agreement, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful. Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in appearing at, participating in or defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

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(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners or any other Persons who have acquired interests in the Partnership Interests, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the

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Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval or Unitholder approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval or Unitholder approval. If Special Approval is sought, then it shall be presumed that, in making its decision, the Conflicts Committee acted in good faith, and if neither Special Approval nor Unitholder approval is sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement or of any duty hereunder or existing at law, in equity or otherwise.

(b) Whenever the General Partner, or any committee of the Board of Directors (including the Conflicts Committee), makes a determination or takes or declines to take any other action, or any of its Affiliates causes the General Partner to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, such committee or such Affiliates causing the General Partner to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards (including fiduciary standards) imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.

(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty (including any fiduciary duty) or obligation whatsoever to the Partnership, any Limited Partner and any other Person bound by this Agreement, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrases, “at the option of the General Partner,” “in its sole discretion” or some variation of those phrases, are used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity.

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(d) The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a partnership.

(e) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be in its sole discretion.

(f) Except as expressly set forth in this Agreement or the Delaware Act, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(g) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner may rely upon, and shall be protected in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership.

Section 7.11 Purchase or Sale of Partnership Interests. The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Interests; provided that, except as permitted pursuant to Section 4.9, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. As long as Partnership Interests are held by any Group Member, such Partnership Interests shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Interests for its own account, subject to the provisions of Articles IV and X.

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Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Interests that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Interests (the “Holder”) to dispose of the number of Partnership Interests it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Interests covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Interests specified by the Holder; provided, that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a); and provided further, however, that if the Conflicts Committee determines that a postponement of the requested registration would be in the best interests of the Partnership and its Partners due to a pending transaction, investigation or other event, the filing of such registration statement or the effectiveness thereof may be deferred for up to six months, but not thereafter. In connection with any registration pursuant to the immediately preceding sentence, the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Interests subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Interests in such states. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of Partnership Interests for cash (other than an offering relating solely to a benefit plan), the Partnership shall use all commercially reasonable efforts to include such number or amount of Partnership Interests held by any Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the Partnership Interests of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of Partnership Interests pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Partnership Interests would adversely and materially affect the timing or success of the offering, the Partnership shall include in such offering only that number or amount, if any, of Partnership Interests held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the

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underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Interests were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or free writing prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d) The provisions of Section 7.12(a) and Section 7.12(b) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Interests with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, that the Partnership shall not be required to file successive registration statements covering the same Partnership Interests for which registration was demanded during such two-year period. The provisions of Section 7.12(c) shall continue in effect thereafter.

(e) The rights to cause the Partnership to register Partnership Interests pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Interests, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Interests with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(f) Any request to register Partnership Interests pursuant to this Section 7.12 shall (i) specify the Partnership Interests intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Interests for distribution,

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(iii) describe the nature or method of the proposed offer and sale of Partnership Interests, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Interests.

Section 7.13 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting. The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Interests, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures, including Operating Surplus and Adjusted Operating Surplus, by making such adjustments to its accrual basis books to account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.

Section 8.2 Fiscal Year. The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 90 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any

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reasonable means, to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b) As soon as practicable, but in no event later than 45 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means, to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(c) The General Partner shall be deemed to have made a report available to each Record Holder as required by this Section 8.3 if it has either (i) filed such report with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such report is publicly available on such system or (ii) made such report available on any publicly available website maintained by the Partnership.

ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information. The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable period or years that it is required by law to adopt, from time to time, as determined by the General Partner. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(h) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies. Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership

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funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

Section 9.4 Withholding; Tax Payments.

(a) The General Partner may treat taxes paid by the Partnership on behalf of, all or less than all of the Partners, either as a distribution of cash to such Partners or as a general expense of the Partnership, as determined appropriate under the circumstances by the General Partner

(b) Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income or from a distribution to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Limited Partners.

(a) By acceptance of the transfer of any Limited Partner Interests in accordance with Article IV or the acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger or consolidation or conversion pursuant to Article XIV, and except as provided in Section 4.8, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests transferred or issued to such Person when any such transfer or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement and (iv) makes the consents, acknowledgements and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.8.

(b) The name and mailing address of each Limited Partner shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.

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(c) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(a).

Section 10.2 Admission of Successor General Partner. A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership. To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);

(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its General Partner Interest pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

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(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 11:59 pm, prevailing Central Time, on December 31, 2020, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 11:59 pm, prevailing Central Time, on December 31, 2020, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal pursuant to Section 11.1(a)(i), a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1 unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.3.

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Section 11.2 Removal of the General Partner. The General Partner may be removed if such removal is approved by the Unitholders holding at least 662/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the outstanding Common Units and Class B Units, if any, voting as a class, and a majority of the outstanding Subordinated Units, voting as a class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.3. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.3, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.3.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates’ general partner interest (or equivalent interest), if any, in the other Group Members and all of its or its Affiliates’ right to receive the Management Incentive Fee (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the

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determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert may consider the value of the Units, including the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner, the value of the right to receive the Management Incentive Fee and the General Partner Interest and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and the Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed the Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner Interest of the Departing General Partner by (B) a percentage equal to 100% less the Percentage Interest of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.4 Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages. Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist:

(a) the Subordinated Units held by any Person will immediately and automatically convert into Common Units on a one-for-one basis, provided (i) neither such Person nor any of its Affiliates voted any of its Units in favor of the removal and (ii) such Person is not an Affiliate of the successor General Partner; and

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(b) if all of the Subordinated Units convert into Common Units pursuant to Section 11.4(a), all Cumulative Common Unit Arrearages on the Common Units will be extinguished and the Subordination Period will end;

provided, that such converted Subordinated Units shall remain subject to the provisions of Sections 5.5(c)(ii), 6.1(d)(x) and 6.7.

Section 11.5 Withdrawal of Limited Partners. No Limited Partner shall have any right to withdraw from the Partnership; provided, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution. The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, 11.2 or 12.2, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership. Subject to Section 12.2, the Partnership shall dissolve, and its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and such successor is admitted to the Partnership pursuant to this Agreement;

(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution. Upon (a) an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this

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Agreement; provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability under the Delaware Act of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator. Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units, Subordinated Units and Class B Units, voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units, Subordinated Units and Class B Units, voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units, Subordinated Units and Class B Units, voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4 Liquidation. The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or

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other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership. Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions. The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition. To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration. No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable period of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner. Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

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

(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(d) a change that the General Partner determines (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of

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Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable period of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable period of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of any class or series of Partnership Interests and options, rights, warrants and appreciation rights relating to the Partnership Interests pursuant to Section 5.6;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4 or 7.1(a);

(k) a merger, conveyance or conversion pursuant to Section 14.3(d); or

(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures. Amendments to this Agreement may be proposed only by the General Partner. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve any amendment to this Agreement and may decline to do so in its sole discretion, and, in declining to propose or approve an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. An amendment shall be effective upon its approval by the General Partner and, except as otherwise provided by Section 13.1 or 13.3, the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each

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proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any amendments. The General Partner shall be deemed to have notified all Record Holders as required by this Section 13.2 if it has either (i) filed such amendment with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such amendment is publicly available on such system or (ii) made such amendment available on any publicly available website maintained by the Partnership

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of (i) in the case of any provision of this Agreement other than Section 11.2 or Section 13.4, reducing such percentage or (ii) in the case of Section 11.2 or Section 13.4, increasing such percentage, unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced or increased, as applicable.

(b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of (including requiring any holder of a class of Partnership Interests to make additional Capital Contributions to the Partnership) any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict, change or modify in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld in its sole discretion.

(c) Except as provided in Section 14.3 or Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected. If the General Partner determines an amendment does not satisfy the requirements of Section 13.1(d)(i) because it adversely affects one or more classes of Partnership Interests, as compared to other classes of Partnership Interests, in any material respect, such amendment shall only be required to be approved by the adversely affected class or classes.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

Section 13.4 Special Meetings. All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of

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the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting is given as provided in Section 16.1. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting. Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6 Record Date. For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Adjournment. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes. The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove

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the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9 Quorum and Voting. The holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement (including Outstanding Units deemed owned by the General Partner). In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units entitled to vote at such meeting (including Outstanding Units deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10 Conduct of a Meeting. The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting. If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting, without a vote and without prior notice, if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Outstanding Units deemed owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot, if any, submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership

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does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner and (b) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners. Nothing contained in this Section 13.11 shall be deemed to require the General Partner to solicit all Limited Partners in connection with a matter approved by the holders of the requisite percentage of Units acting by written consent without a meeting.

Section 13.12 Right to Vote and Related Matters

(a) Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER, CONSOLIDATION OR CONVERSION

Section 14.1 Authority. The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion. Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

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(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) the name and jurisdiction of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity interests of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity, then the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of equity interests represented by certificates, upon the surrender of such certificates, which cash, property or interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, certificate of formation or limited liability company agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement ( provided , that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain and stated in the certificate of merger); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

(i) the name of the converting entity and the converted entity;

(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or

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obligations of the converted entity or another entity, or for the cancellation of such equity securities;

(v) in an attachment or exhibit, the certificate of limited partnership of the Partnership; and

(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;

(vii) the effective time of the conversion, which may be the date of the filing of the articles of conversion or a later date specified in or determinable in accordance with the Plan of Conversion ( provided , that if the effective time of the conversion is to be later than the date of the filing of such articles of conversion, the effective time shall be fixed at a date or time certain and stated in such articles of conversion); and

(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Limited Partners.

(a) Except as provided in Section 14.3(d), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion and the merger, consolidation or conversion contemplated thereby, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Sections 14.3(d) and 14.3(e), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or Plan of Conversion, as the case may be, contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or the Plan of Conversion, as the case may be.

(c) Except as provided in Sections 14.3(d) and 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already treated as such), (ii) the sole purpose of such conversion, merger, or

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conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Interests to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Interests Outstanding immediately prior to the effective date of such merger or consolidation.

(f) Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.

Section 14.4 Certificate of Merger. Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Effect of Merger, Consolidation or Conversion.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

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(b) At the effective time of the certificate of conversion, for all purposes of the laws of the State of Delaware:

(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall remain vested in the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and are enforceable against the converted entity by such creditors and obligees to the same extent as if the liabilities and obligations had originally been incurred or contracted by the converted entity;

(v) the Partnership Interests that are to be converted into partnership interests, shares, evidences of ownership, or other rights or securities in the converted entity or cash as provided in the plan of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable in its sole discretion, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with

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Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates, in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article III, Article IV, Article V, Article VI, and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article III, Article IV, Article V, Article VI and Article XII).

(c) In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

ARTICLE XVI

GENERAL PROVISIONS

Section 16.1 Addresses and Notices; Written Communications.

(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Interests at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of

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any Person who may have an interest in such Partnership Interests by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report given or made in accordance with the provisions of this Section 16.1 is returned marked to indicate that such notice, payment or report was unable to be delivered, such notice, payment or report and, in the case of notices, payments or reports returned by the United States Postal Service (or other physical mail delivery mail service outside the United States of America), any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) or other delivery if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms “in writing”, “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 16.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 16.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Third-Party Beneficiaries. Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

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Section 16.8 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) without execution hereof.

Section 16.9 Applicable Law; Forum, Venue and Jurisdiction.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a fiduciary duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware, in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;

(ii) irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claim, suit, action or proceeding;

(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding; and

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in clause (v) hereof shall affect or limit any right to serve process in any other manner permitted by law.

Section 16.10 Invalidity of Provisions. If any provision or part of a provision of this Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and part thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and

QR Energy, LP

First Amended and Restated Agreement of Limited Partnership

A-87

EXHIBIT A
to the First Amended and Restated
Agreement of Limited Partnership of
QR Energy, LP

Certificate Evidencing Common Units
Representing Limited Partner Interests in
QR Energy, LP


No.	Common Units

In accordance with Section 4.1 of the First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, as amended, supplemented or restated from time to time (the “Partnership Agreement”), QR Energy, LP, a Delaware limited partnership (the “Partnership”), hereby certifies that (the “Holder”) is the registered owner of Common Units representing limited partner interests in the Partnership (the “Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 5 Houston Center, 1401 McKinney Street, Suite 2400, Houston, Texas 77010. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF QR ENERGY, LP THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF QR ENERGY, LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE QR ENERGY, LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). QRE GP, LLC, THE GENERAL PARTNER OF QR ENERGY, LP, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF QR ENERGY, LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

The Holder, by accepting this Certificate, (i) shall bound by the Partnership Agreement, (ii) represents and warrants that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement and (iii) makes the given and waivers the consents and approvals contained in the Partnership Agreement.

QR Energy, LP

First Amended and Restated Agreement of Limited Partnership

A-90

[Reverse of Certificate]
ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:


TEN COM — as tenants in common		UNIF GIFT/TRANSFERS MIN ACT
TEN ENT — as tenants by the entireties		Custodian
JT TEN — as joint tenants with right of survivorship and not as tenants in common		(Cust) (Minor) Under Uniform Gifts/Transfers to CD Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

ASSIGNMENT OF COMMON UNITS OF
QR ENERGY, LP

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto




(Please print or typewrite name and address of assignee)		(Please insert Social Security or other identifying number of assignee)

Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of QR Energy, LP.

Date:

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

NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular without alteration, enlargement or change.

(Signature)

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

QR Energy, LP

First Amended and Restated Agreement of Limited Partnership

A-92

APPENDIX B

GLOSSARY OF TERMS

The following includes a description of the meanings of some of the oil and natural gas industry terms used in this prospectus. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been excerpted from the applicable definitions contained in Rule 4-10(a) of Regulation S-X.

Adjusted Operating Surplus for any period means:

(a) operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under the definition of “Operating Surplus”; less

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

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

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

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

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

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

(a) less, the amount of cash reserves established by our general partner to:


	•	provide for the proper conduct of our business;

	•	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 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 next four quarters);

(b) 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.

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

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

Bbl/d: One Bbl per day.

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

Boe/d: One Boe per day.

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

Capital Surplus means any distribution of available cash in excess of our cumulative operating surplus. Accordingly, capital surplus would generally be generated by:


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

	•	sales of our equity securities;

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

	•	capital contributions;

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

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

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

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

MBbls: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

MBtu/d: One thousand Btu per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBoe: One million Boe.

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MMBtu: One million British thermal units.

MMcf: One thousand Mcf.

Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage working interest.

Net Production: Production that is owned by us less royalties and production due others.

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

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


	•	repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus below when such repayment actually occurs;

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

	•	growth capital expenditures;

	•	actual maintenance capital expenditures;

	•	investment capital expenditures;

	•	payment of transaction expenses relating to interim capital transactions;

	•	distributions to our partners; or

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

Operating Surplus for any period means:


	•	$40.0 million; plus

	•	all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, which include the following:


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

	•	sales of equity interests;

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

	•	capital contributions received;


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

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

	•	cash distributions paid on equity issued (including distributions on common units, if any) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less

	•	all of our operating expenditures after the closing of this offering; less

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

	•	all working capital borrowings not repaid within twelve months after having been incurred; less

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

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved Reserves: Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved

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classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves: Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

definition of this term can be viewed on the Web site at http://www.sec.gov/Divisions/corpfin/forms/.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Subordination Period: will end on the earlier of:


	•	the later to occur of (a) the second anniversary of the closing of this offering and (b) such time 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.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore: The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

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Appendix C

November 26, 2010

Mr. Kenneth R. Michie

Vice President – Exploitation

QRE GP, LLC

Five Houston Center

1401 McKinney Street, Suite 2400

Houston, Texas 77010


	Re:	QR Energy, LP

Reserves and Future Net Revenues

As of June 30, 2010

SEC Price Case

Dear Mr. Michie:

At your request, Miller and Lents, Ltd. (MLL) estimated the proved oil, gas, and natural gas liquids (NGL) reserves and projected future net revenues associated with these reserves as of June 30, 2010, attributable to the QR Energy, LP (QR Energy) net interests in properties located in the continental United States in Arkansas, Louisiana, Mississippi, New Mexico, Oklahoma, and Texas. These properties were specified by Quantum Resources Management, LLC (QRM) as properties to be assigned to QR Energy, LP from QRM. This report covers all of the properties of QR Energy and has been prepared for use in connection with QR Energy’s Registration Statement on Form S1 and other such purposes as may be required by QR Energy. This report was completed on November 26, 2010.

MLL preformed its evaluation, designated as the SEC Price Case, using prices, operating expenses, and capital expenditures provided by QR Energy. The SEC Price Case assumes no future escalation of product prices, operating expenses or capital expenditures above the respective June 30, 2010 values. The aggregate results of MLL’s evaluation are as follows:

Reserves and Future Net Revenues as of June 30, 2010

Net Reserves

Future Net Revenues

Discounted at

Oil,

Gas,

NGL,

Undiscounted,

10% Per Year,

Reserves Category

MBbls.

MMcf

MBbls.

Proved Producing

11,195.9

41,954.9

1,355.0

554,389.4

302,393.8

Proved Nonproducing

184.6

2,745.3

86.1

19,935.8

11,695.1

Proved Developed

11,380.5

44,700.2

1,441.1

574,325.2

314,088.9

Proved Undeveloped

7,670.1

9,987.8

47.1

401,667.8

153,167.2

Total Proved

19,050.5

54,688.0

1,488.2

975,993.0

467,256.1

Two Houston Center • 909 Fannin Street, Suite 1300 • Houston, Texas 77010

Telephone 713-651-9455 • Telefax 713-654-9914 • e-mail: mail@millerandlents.com

C-1


Mr. Kenneth R. Michie	November 26, 2010


QRE GP, LLC	Page 2

Reserves and future net revenues were estimated in accordance with the standards of the Securities and Exchange Commission Regulation S-X, Rule 4-10(a) as shown in Appendix 1. Gas volumes for each property are stated at the pressure and temperature bases appropriate for the sales contract or state regulatory authority. Total gas reserves were obtained by summing the reserves for all the individual properties and are, therefore, stated herein at a mixed pressure base. No provisions for the possible consequences of product sales imbalances, if any, were included in MLL’s projections since we have received no relevant data. Analysis of gas plants and gathering systems was beyond the scope of this evaluation. Therefore, MLL assumed that these facilities will continue to operate through the economic life of the wells included herein.

Future net revenues as used herein are defined as the total revenues attributable to (1) QR Energy’s working interest less royalties, overriding royalties, production and ad valorem taxes, operating costs, and future capital expenditures; and (2) QR Energy’s royalty interest less production and ad valorem taxes. MLL’s projections of future net revenues are shown both undiscounted and discounted at 10 percent per year. The effects of depreciation, depletion, or Federal Income Tax are not considered. Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent fair market value for the estimated reserves.

Abandonment costs were provided by QR Energy except where it was assumed that the abandonment costs would be equal to the salvage value of existing equipment upon abandonment of the wells. Future costs, if any, to satisfy environmental standards were not deducted from future net revenues as such estimates were beyond the scope of this assignment.

Minor precision inconsistencies in subtotals or totals may exist in the report due to truncation or rounding of aggregated values. There are instances in the cash flow summaries where negative production and future net revenue values are reported. These values are the result of the subtraction of one producing scenario from another to calculate the incremental effect of undertaking a project which accelerates production.

The prices used for the reserves projections herein are in accordance with Securities and Exchange Commission standards. Benchmark prices of $75.76 per barrel based on the West Texas Intermediate Spot Price at Cushing, Oklahoma and $4.10 per MMBtu based on the Henry Hub Spot Price were used for this evaluation. NGL prices were based on differentials to the oil price. These prices represent the twelve month average of the first-day-of-the-month price for each month within the twelve month period prior to June 30, 2010. Price adjustments were made for each property based on differentials between benchmark and actual prices as estimated by QR Energy and include considerations such as gas Btu content, oil gravity, and transportation charges. The average adjusted product prices for the total of all proved reserves were $71.52 per barrel of oil, $44.46 per barrel of NGL and $3.99 per Mcf of gas. Operating costs as of June 30, 2010 were provided by QR Energy. Costs include per-well and per-unit of production components that were held constant for the remaining economic life of each property. All future capital was unescalated.

Forecasts of production and future net revenues for the total reserves by category are included as Exhibits 1 through 4. A one-line summary sorted by reserves category, area, field group, and lease is included as Exhibit 5. Forecasts of production and future net revenues for the four producing areas: (1) Arklatex, (2) Gulf Coast, (3) Mid-Continent, and (4) Permian are included in Exhibits 6 through 19.

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Mr. Kenneth R. Michie	November 26, 2010


QRE GP, LLC	Page 3

Reserves estimates were based on decline curve extrapolations, material balance calculations, volumetric calculations, analogies, or combinations of these methods for each well, reservoir, or field as necessary to prepare the report. Proved producing reserves were based primarily on extrapolation of historical performance trends. In those wells producing at high water-cuts, water-oil rations versus cumulative production trends were used to estimate reserves. MLL relied mainly on production rate versus time decline curves. Estimates and projections for proved nonproducing, and proved undeveloped reserves were mainly based on volumetric calculations or analogies. Reserves estimates from analogies and volumetric calculations are often less certain than reserves estimates based on well performance obtained over a period during which a substantial portion of the reserves were produced.

In conducting this evaluation, MLL relied upon production histories, well test data, well logs, and other engineering and geological data supplied by QR Energy. To a lesser extent, non-confidential data existing in the files of MLL and data from commercial services and of public record were used. The operating expenses, ownership interests, reversion provisions, current payout status, NGL yields, product prices and price differentials were provided by QR Energy. MLL also relied upon QR Energy’s representations to us of planned schedules and the estimated costs for future well work. All of these data were accepted as represented, as verification of such was beyond the scope of MLL’s assignment.

The evaluations presented in this report, with the exception of those parameters specified by others, reflect MLL’s informed judgment based on standards as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Information Approved by SPE Board in 2001, revised as of February 19, 2007, (Appendix 2), but are subject to the inherently imprecise nature of reserves estimation and other reserves information as described in same document. Government policies, regulations, and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report.

Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in QR Energy or any affiliate of Quantum Resources Management, LLC. MLL’s compensation for the required investigations and preparation of this report is not contingent upon the results obtained and reported, and we have not performed other work that would affect MLL’s objectivity. Production of this report was supervised by an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 25 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

Very truly yours,

MILLER AND LENTS, LTD.

Texas Registered Engineering Firm No. F-1442


	By	/s/ R. Lee Comer, Jr., P.E.

R. Lee Comer, Jr., P.E.

Vice President

RLC/jj

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Appendix 1

Page 1 of 3

Reserves Definitions In Accordance With
Securities and Exchange Commission Regulation S-X

Reserves

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Proved Oil and Gas Reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

1. The area of the reservoir considered as proved includes:

a. The area identified by drilling and limited by fluid contacts, if any, and

b. Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

2. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

3. Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

4. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

a. Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

b. The project has been approved for development by all necessary parties and entities, including governmental entities.

5. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month

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Appendix 1

Page 2 of 3

period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed Oil and Gas Reserves

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

1. Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

2. Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped Oil and Gas Reserves

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

1. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

2. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

3. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined below, or by other evidence using reliable technology establishing reasonable certainty.

Analogous Reservoir

Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

1. Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

2. Same environment of deposition;

3. Similar geological structure; and

4. Same drive mechanism.

Reservoir properties must, in aggregate, be no more favorable in the analog than in the reservoir of interest.

Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

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1. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

2. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

3. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

4. See also guidelines in Items 4 and 6 under Possible Reserves.

Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

1. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

2. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

3. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

4. The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

5. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

6. Pursuant to Item 3 under Proved Oil and Gas Reserves, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

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Standards Pertaining
to the Estimating and Auditing
of Oil and Gas Reserves Information
Approved by SPE Board in June 2001

Revision as of February 19, 2007

Foreword:

The principles and concepts established in the original version of this document in 1977 were well founded given the state of the petroleum industry at that time. However, the industry has now become significantly more diversified and complex through epochal changes in technology, contractual and licensing terms, corporate governance issues, and regulatory reporting and compliance. The original principles remain unchanged in this (proposed) revision, but an attempt has been made to incorporate the enlarged necessity for somewhat more stringent requirements in the expectations and standards imposed on reserves professionals today. The 2007 revision of this document includes those modifications required to incorporate the 2007 SPE/WPC/AAPG/SPEE Reserves and Resources System. This document is the result of an ongoing update process for this and all other vital components of the Petroleum Resources Management System, but it remains limited to those quantities contained within the system that are classified as Reserves.

A second objective has been to explain the use of the terms “auditors” and “auditing” as used in this document and to clarify the difference in the same terms as they are used in the financial and accounting professions.

A third modification is an attempt to acknowledge greater recognition and significance to the importance of the integration of geoscience and engineering as an essential feature in the preparation of reliable petroleum reserves information.

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TABLE OF CONTENTS


ARTICLE I
THE BASIS AND PURPOSE OF DEVELOPING STANDARDS PERTAINING TO THE ESTIMATING AND AUDITING OF PETROLEUM RESERVES INFORMATION
	1.1	The Nature and Purpose of Estimating and Auditing Petroleum Reserves Information	C-10
	1.2	Estimating and Auditing Reserves Information in Accordance With Generally Accepted Engineering and Evaluation Principles	C-10
	1.3	The Inherently Imprecise Nature of Reserves Information	C-10
	1.4	The Need for Standards Governing the Estimating and Auditing of Reserves Information	C-10

ARTICLE II
DEFINITIONS OF SELECTED TERMS
	2.1	Applicability of Definitions	C-11
	2.2	Defined Terms	C-11

ARTICLE III
PROFESSIONAL QUALIFICATIONS OF RESERVES ESTIMATORS AND RESERVES AUDITORS
	3.1	The Importance of Professionally Qualified Reserves Estimators and Reserves Auditors	C-13
	3.2	Professional Qualifications of Reserves Estimators	C-13
	3.3	Professional Qualifications of Reserves Auditors	C-14

ARTICLE IV
STANDARDS OF INDEPENDENCE, OBJECTIVITY, AND CONFIDENTIALITY FOR RESERVES ESTIMATORS AND RESERVES AUDITORS
	4.1	The Importance of Independent or Objective Reserves Estimators and Reserves Auditors	C-14
	4.2	Requirement of Independence for Consulting Reserves Estimators and Consulting Reserves Auditors	C-14
	4.3	Standards of Independence for Consulting Reserves Estimators and Consulting Reserves Auditors	C-15
	4.4	Requirement of Objectivity for Reserves Auditors Internally Employed by Entities	C-16
	4.5	Standards of Objectivity for Reserves Auditors Internally Employed by Entities	C-16
	4.6	Requirement of Confidentiality	C-17

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ARTICLE V
STANDARDS FOR ESTIMATING RESERVES AND OTHER RESERVES INFORMATION
	5.1	General Considerations in Estimating Reserves Information	C-17
	5.2	Adequacy of Database in Estimating Reserves Information	C-17
	5.3	Estimating Reserves	C-18
	5.4	Estimating Reserves by the Volumetric Method	C-18
	5.5	Estimating Reserves by Analyzing Performance Data	C-18
	5.6	Estimating Reserves by Using Mathematical Models	C-18
	5.7	Estimating Reserves by Analogy to Comparable Reservoirs	C-19
	5.8	Categorization of Reserves	C-19
	5.9	Deterministic and Probabilistic Methods of Estimating Reserves	C-19
	5.10	Estimated Future Rates of Production	C-20
	5.11	Estimating Other Reserves Information	C-20

ARTICLE VI
STANDARDS FOR AUDITING RESERVES AND OTHER RESERVES INFORMATION
	6.1	The Concept of Auditing Reserves and Other Reserves Information	C-21
	6.2	Limitations on Responsibility of Reserves Auditors	C-21
	6.3	Understanding Among an Entity, Its Independent Public Accountants, and the Reserves Auditors	C-22
	6.4	Procedures for Auditing Reserves Information	C-22
	6.5	Records and Documentation With Respect to Audit	C-24
	6.6	Forms of Unqualified Audit Opinions	C-24

EXHIBITS
	A	Illustrative Unqualified Audit Opinion of Consulting Reserves Auditor
	B	Illustrative Unqualified Audit Opinion of Reserves Auditor Internally Employed by an Entity

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Article I — The Basis and Purpose of Developing Standards Pertaining to the Estimating and Auditing of Petroleum Reserves Information¹


1.1	The Nature and Purpose of Estimating and Auditing Petroleum Reserves Information

Estimates of Reserves Information are made by or for Entities as a part of their ongoing business practices. Such Reserves Information typically may include, among other things, estimates of (i) the reserves quantities, (ii) the future producing rates from such reserves, (iii) the future net revenue from such reserves, and (iv) the present value of such future net revenue. The exact type and extent of Reserves Information must necessarily take into account the purpose for which such Reserves Information is being prepared and, correspondingly, statutory and regulatory provisions, if any, that are applicable to such intended use of the Reserves Information. Reserves Information may be limited to Proved Reserves or may involve other categories of reserves as appropriate to the estimate.


1.2	Estimating and Auditing Reserves Information in Accordance With Generally Accepted Engineering and Evaluation Principles

The estimating and auditing of Reserves Information is predicated upon certain historically developed principles of geoscience, petroleum engineering, and evaluation methodologies, which are in turn based on principles of physical science, mathematics, and economics. Although these generally accepted geological, engineering, and evaluation principles are predicated on established scientific concepts, the application of such principles involves extensive judgments by qualified individuals and is subject to changes in (i) existing knowledge and technology; (ii) fiscal and economic conditions; (iii) applicable contractual, statutory, and regulatory provisions; and (iv) the purposes for which the Reserves information is to be used.


1.3	The Inherently Imprecise Nature of Reserves Information

The reliability of Reserves Information is considerably affected by several factors. Initially, it should be noted that Reserves Information is imprecise due to the inherent uncertainties in, and the limited nature of, the accumulation and interpretation of data upon which the estimating and auditing of Reserves Information is predicated. Moreover, the methods and data used in estimating Reserves Information are often necessarily indirect or analogical in character rather than direct or deductive. Furthermore, the persons estimating and auditing Reserves Information are required, in applying generally accepted petroleum engineering and evaluation principles, to make numerous unbiased judgments based upon their educational background, professional training, and professional experience. The extent and significance of the judgments to be made are, in themselves, sufficient to render Reserves Information inherently imprecise.


1.4	The Need for Standards Governing the Estimating and Auditing of Reserves Information

The Society of Petroleum Engineers (the “Society”) has determined that the Society should adopt these Standards Pertaining to the Estimating and Auditing of Petroleum Reserves and Reserves Information (the “Standards”). The adoption of these Standards by the Society fulfills at least three useful objectives.

First, although some users of Reserves Information are cognizant of the general principles that are applied to databases in the estimation of Reserves Information, the judgments required in estimating

¹ These Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (the “Standards”) are not intended to bind the members of the Society of Petroleum Engineers (the “Society”) or anyone else, and the Society imposes no sanctions for the nonuse of these Standards. Each person estimating and auditing oil and gas Reserves Information is encouraged to exercise his or her own judgment concerning the matters set forth in these Standards. The Society welcomes comments and suggested changes in regard to these Standards.

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and auditing Reserves Information, and the inherently imprecise nature of Reserves Information, many users of Reserves Information continue to fail to understand such matters. The adoption, publication, and distribution of these Standards should enable users of Reserves Information to understand these matters more fully and therefore place the appropriate level of confidence on Reserves Information.

Second, the wider dissemination of Reserves Information through public financial reporting, such as that required by various governmental authorities, makes it imperative that the users of Reserves Information have a general understanding of the methods of, and limitations on, estimating and auditing Reserves Information.

Third, as Reserves Information proliferates in terms of the types of information available and the broader dissemination thereof, it becomes increasingly important that Reserves Information be estimated and audited on a consistent basis by competent, well-trained professional geoscientists and engineers. Compliance with these Standards is a method of facilitating evaluation and comparisons of Reserves Information by the users thereof.

In order to accomplish the three above-discussed objectives, the Society has included in these Standards (i) definitions of selected terms pertaining to the estimation and evaluation of Reserves Information, (ii) qualifications for persons estimating and auditing Reserves Information, (iii) standards of independence and objectivity for such persons, (iv) standards for estimating reserves and other Reserves Information, and (v) standards for auditing reserves and other Reserves Information. Although these Standards are predicated on generally accepted geoscience, petroleum engineering, and economic evaluation principles, it may in the future become necessary, for the reasons set forth in Section 1.2, to clarify or amend certain of these Standards. Accordingly, the Society, as a part of its governance process, will periodically review these standards and determine whether to amend these Standards or publish clarifying statements.

Note that these Standards apply independently of the classification system and associated guidelines adopted by the entity; the reference system should be clearly identified.

Article II — Definitions of Selected Terms


2.1	Applicability of Definitions

In preparing a report or opinion, persons estimating and auditing Reserves Information shall ascribe, to reserves and other significant terms used therein, the current petroleum reserves and resources definitions and classification system promulgated by the Society or such other definitions as he or she may reasonably consider appropriate in accordance with generally accepted petroleum engineering and evaluation principles, provided, however, that (i) such report or opinion should define, or make reference to a definition of, each significant term that is used therein and (ii) the definitions used in any report or opinion must be consistent with statutory and regulatory provisions, if any, that apply to such report or opinion in accordance with its intended use.


2.2	Defined Terms

The definitions set forth in this Section are applicable for all purposes of these Standards:

(a) Entity. An Entity is a corporation, joint venture, partnership, trust, individual, principality, agency, or other person engaged directly or indirectly in (i) the exploration for, or production of, oil and gas; (ii) the acquisition of properties or interests therein for the purpose of conducting such exploration or production; or (iii) the ownership of properties or interests therein with respect to which such exploration or production is being, or will be, conducted.

(b) Reserves Estimator. A Reserves Estimator is a person who is designated to be in responsible charge for estimating and evaluating reserves and other Reserves Information. A Reserves Estimator either may personally make the estimates and evaluations of Reserves Information or may supervise and approve the estimation and evaluation thereof by others.

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(c) Entity Reserves Report. An Entity Reserves Report may be prepared by an internal or external estimator for any of several purposes, all of which should be clearly disclosed in the report. Such report is to be considered valid for only those properties identified and included in the report as of the effective report date. To be termed an Entity Reserves Report, the report should represent all or at least 80% of an entity’s reserves, future production, and/or revenues. An Entity Reserves Report should clearly indicate the relative importance of the properties included and any properties excluded from the Entity Reserves Report. An Entity Reserves Report for any purpose should contain adequate disclosures to fully inform the user about the definitions and reserves classifications employed, qualifications and independence of the estimator, confidentiality restrictions, and any unusual circumstances or report qualifiers, and it should include, but not be limited to, authorization for the report, the sources and adequacy and reliability of the underlying geological and engineering data, assumptions employed, and any limitations imposed on the distribution and use of the Entity Reserves Report.

(d) Property Reserves Report. A Property Reserves Report may contain Reserves Information limited to one or more reservoirs, fields, and/or projects but is not sufficiently extensive to be considered an Entity Reserves Report. All of the other qualifications in (c) above apply.

(e) Reserves Auditor. A Reserves Auditor is a person who is designated to be in responsible charge for the conduct of an audit with respect to Reserves Information estimated by others. A Reserves Auditor either may personally conduct an audit of Reserves Information or may supervise and approve the conduct of an audit thereof by others. A Reserves Auditor may be an employee of the entity or an employee of an external independent firm.

(f) Reserves Audit. A Reserves Audit is the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, (4) the classification of reserves appropriate to the relevant definitions used, and (5) the reasonableness of the estimated reserves quantities and/or the Reserves Information. The term “reasonableness” cannot be defined with precision but should reflect a quantity and/or value difference of not more than plus or minus 10%, or the subject Reserves Information does not meet minimum recommended audit standards. This tolerance can be applied to any level of reserves or Reserves Information aggregation, depending upon the nature of the assignment, but is most often limited to Proved Reserves Information. A separate predetermined and disclosed tolerance may be appropriate for other reserves classifications. Often a reserves audit includes a detailed review of certain critical assumptions and independent assessments with acceptance of other information less critical to the reserves estimation. Typically, a reserves audit letter or report is prepared, clearly stating the assumptions made. A reserves audit should be of sufficient rigor to determine the appropriate reserves classification for all reserves in the property set evaluated and to clearly state the reserves classification system being utilized. In contrast to the term “audit” as used in a financial sense, a reserves audit is generally less rigorous than a reserves report.

(g) Financial Audit. A Financial Audit, as contrasted with a Reserves Audit, is typically described as a periodic examination of an organization’s financial records and accounts, performed in an effort to verify that funds were used as they were intended and consistent with established financial management practices.

(h) Process Review. A Process Review is the result of an investigation by a person who is qualified by experience and training equivalent to that of a Reserves Auditor to address the adequacy and effectiveness of an entity’s internal processes and controls relative to reserves estimation. These internal processes and controls most often include some form of an independent internal or external reserves audit system. The Process Review should not include an opinion relative to the reasonableness of the reserves quantities or Reserves Information and should be limited to the process and control

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system reviewed. The term process review includes reports that have also been termed “procedural audits” or “procedural reviews” in the industry. Although such reviews may provide value to the entity, an external or internal Process Review is not of sufficient rigor to establish appropriate classifications and quantities of reserves and should not be represented to the public as being equivalent to an audit of reserves.

(i) Reserves Information. Reserves Information consists of various estimates pertaining to the extent and value of petroleum properties. Reserves Information will include (i) estimates of petroleum reserves and may, but will not necessarily, include estimates of (ii) the future production rates from such reserves, (iii) the future net revenue from such reserves, and (iv) the present value of such future net revenue. All such Reserves Information should be estimated and classified as appropriate to stated reserves definitions.

Article III — Professional Qualifications of Reserves Estimators and Reserves Auditors


3.1	The Importance of Professionally Qualified Reserves Estimators and Reserves Auditors

Reserves Information is prepared and audited, respectively, by Reserves Estimators and Reserves Auditors, who are often assisted by other professionals and by paraprofessionals and clerical personnel. Reserves Estimators and Reserves Auditors may be (i) employees of an Entity itself or (ii) stockholders, proprietors, partners, or employees of an independent firm of petroleum consultants with which an arrangement has been made for the estimating or auditing of Reserves Information. Irrespective of the nature of their employment, however, Reserves Estimators and Reserves Auditors must (i) examine and interpret the available data necessary to estimate or audit Reserves Information; (ii) perform such tests, and consider such matters, as may be necessary to evaluate the sufficiency of the database; and (iii) make such calculations and estimates, and apply such tests and standards, as may be necessary to estimate or audit reserves and other Reserves Information. For the reasons discussed in Section 1.3, the proper determination of these matters is highly dependent upon the numerous judgments Reserves Estimators and Reserves Auditors are required to make based upon their educational background, professional training, integrity, and professional experience. Consequently, in order to assure that Reserves Information will be as reliable as possible given the limitations inherent in the estimating and auditing process, it is essential that those in responsible charge for estimating and auditing Reserves Information have adequate professional qualifications such as those set forth in this Article III.


3.2	Professional Qualifications of Reserves Estimators

A Reserves Estimator shall be considered professionally qualified in such capacity if he or she has sufficient educational background, professional training, and professional experience to enable him or her to exercise prudent professional judgment and to be in responsible charge in connection with the estimating of reserves and other Reserves Information. The determination of whether a Reserves Estimator is professionally qualified should be made on an individual-by-individual basis. A Reserves Estimator would normally be considered to be qualified if he or she (i) has a minimum of 3 years’ practical experience in petroleum engineering or petroleum production geology, with at least 1 full year of such experience being in the estimation and evaluation of Reserves Information; and (ii) either (A) has obtained, from a college or university of recognized stature, a bachelor’s or advanced degree in petroleum engineering, geology, or other discipline of engineering or physical science or (B) has received, and is maintaining in good standing, a registered or certified professional engineer’s license or a registered or certified professional geologist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. In the context used herein, it is recommended that experience and competency levels should generally include a clear understanding of several areas of knowledge pertinent to the circumstances and conditions to which they are being applied, which could include industry accepted practices related to (1) the creation and understanding of geological maps and models, (2) the judicious selection of and reliance upon

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appropriate reservoir analogs, (3) appropriate application of and reliance upon seismic information in reserves estimation, (4) fundamentals and limitations of reservoir simulation, (5) basic knowledge and applicability of probabilistic and deterministic assessment methodologies, (6) the use of numerous performance evaluation techniques to confirm and/or refine geological interpretations, (7) the consequences of reliance on computer software without a full understanding of the internal calculation processes, (8) various forms of production licensing and fiscal systems, (9) ongoing training in the relevant or pertinent reserves definitions, and (10) ethics training — all of which should be refreshed periodically through some form of internally or externally provided continuing education.

Reserves Estimators and Auditors are encouraged to recognize the professional obligation to secure ongoing training in the areas described above, whether or not this is provided or required by their employer. A Reserves Estimator should decline an assignment for which he or she is not qualified.


3.3	Professional Qualifications of Reserves Auditors

A Reserves Auditor shall be considered professionally qualified in such capacity if he or she has sufficient educational background, professional training (similar to that described above), and professional experience to enable him or her to exercise prudent professional judgment while acting in responsible charge for the conduct of an audit of Reserves Information estimated by others. The determination of whether a Reserves Auditor is professionally qualified should be made on an individual-by-individual basis and with the recognition and respect of his or her peers. A Reserves Auditor would normally be considered to be qualified if he or she (i) has a minimum of 10 years’ practical experience in petroleum engineering or petroleum production geology, with at least 5 years of such experience being in responsible charge of the estimation and evaluation of Reserves Information; and (ii) either (A) has obtained, from a college or university of recognized stature, a bachelor’s or advanced degree in petroleum engineering, geology, or other discipline of engineering or physical science or (B) has received, and is maintaining in good standing, a registered or certified professional engineer’s license or a registered or certified professional geologist’s license, or the equivalent thereof, from an appropriate governmental authority or professional organization. A Reserves Auditor should decline an assignment for which he or she is not qualified.

Article IV — Standards of Independence, Objectivity, and Confidentiality for Reserves Estimators and Reserves Auditors


4.1	The Importance of Independent or Objective Reserves Estimators and Reserves Auditors

In order that users of Reserves Information may be assured that the Reserves Information has been estimated or audited in an unbiased and objective manner, it is important that Reserves Estimators and Reserves Auditors maintain, respectively, the levels of independence and objectivity set forth in this Article IV. The determination of the independence and objectivity of Reserves Estimators and Reserves Auditors should be made on a case-by-case basis. To facilitate such determination, the Society has adopted (i) standards of independence for consulting Reserves Estimators and consulting Reserves Auditors and (ii) standards of objectivity for Reserves Auditors internally employed by Entities to which the Reserves Information relates. To the extent that the applicable standards of independence and objectivity set forth in this Article IV are not met by Reserves Estimators and Reserves Auditors in estimating and auditing Reserves Information, such lack of conformity with this Article IV shall be disclosed in any report or opinion relating to Reserves Information which purports to have been estimated or audited in accordance with these Standards.


4.2	Requirement of Independence for Consulting Reserves Estimators and Consulting Reserves Auditors

Consulting Reserves Estimators and consulting Reserves Auditors, or any firm of petroleum consultants of which such individuals are stockholders, proprietors, partners, or employees, must be

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independent from any Entity with respect to which such Reserves Estimators, Reserves Auditors, or consulting firms estimate or audit Reserves Information which purports to have been estimated or audited in accordance with these Standards. A statement of such independence shall be made a part of any report containing Reserves Information.


4.3	Standards of Independence for Consulting Reserves Estimators and Consulting Reserves Auditors²

Consulting Reserves Estimators and consulting Reserves Auditors, and any firm of petroleum consultants of which such individuals are stockholders, proprietors, partners, or employees, would not normally be considered independent with respect to an Entity if, during the term of their professional engagement, such Reserves Estimators, Reserves Auditors, or consulting firm:

(a) Investments. Either owned or acquired, or were committed to acquire, directly or indirectly, any material financial interest in (i) such Entity or any corporation or other person affiliated therewith or (ii) any property with respect to which Reserves Information is to be estimated or audited. Any such financial interest, stock, or other ownership in the properties held through direct ownership, trusts, partnerships, or incorporated entities should be disclosed in writing to the entity to determine materiality by the entity and maintained on file by the entity for review by financial auditors.

(b) Joint Business Venture. Either owned or acquired, or were committed to acquire, directly or indirectly, any material joint business investment with such Entity or any officer, director, principal stockholder, or other person affiliated therewith.

(c) Borrowings. Were indebted to such Entity or any officer, director, principal stockholder, or other person affiliated therewith, provided, however, that retainers, advances against work-in-progress, and trade accounts payable arising from the purchase of goods and services in the ordinary course of business shall not constitute indebtedness within the meaning of this Section 4.3(c).

(d) Guarantees of Borrowings. Were indebted to any individual, corporation, or other person under circumstances where the payment of such indebtedness was guaranteed by such Entity or any officer, director, principal stockholder, or other person affiliated therewith.

(e) Loans to Clients. Extended credit to (i) such Entity or any officer, director, principal stockholder, or other person affiliated therewith or (ii) any person having a material interest in any property with respect to which Reserves Information was estimated or audited, provided, however, that trade accounts receivable arising in the ordinary course of business from the performance of petroleum engineering and related services shall not constitute the extension of credit within the meaning of this Section 4.3(e).

(f) Guarantees for Clients. Guaranteed any indebtedness (i) owed by such Entity or any officer, director, principal stockholder, or other person affiliated therewith or (ii) payable to any individual,

² For purposes of this Section 4.3, the term “affiliated” shall, with respect to an Entity, describe the relationship of a person to such Entity under circumstances in which such person directly or indirectly, through one or more intermediaries, controls or is controlled by, or is under common control with, such Entity; provided, however, that commercial banks and other bona fide financial institutions shall not be considered to be affiliated with the Entity to which the Reserves Information relates unless such banks or institutions actively participate in the management of the properties of such Entity.

Unless the context requires otherwise, the term “material” shall, for purposes of this Section 4.3, be interpreted with reference to the net worth of the consulting Reserves Estimators or the consulting Reserves Auditors, or any firm of petroleum consultants of which such individuals are stockholders, proprietors, partners, or employees.

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corporation, entity, or other person having a material interest in the Reserves Information pertaining to such Entity.

(g) Purchases and Sales of Assets. Purchased any material asset from, or sold

any material asset to, such Entity or any officer, director, principal stockholder, or other person affiliated therewith.

(h) Certain Relationships With Client. Were directly or indirectly connected with such Entity as a promoter, underwriter, officer, director, or principal stockholder, or in any capacity equivalent thereto, or were otherwise not separate and independent from the operating and investment decision-making process of such Entity.

(i) Trusts and Estates. Were trustees, participants, or beneficial owners in any trust, or executors, administrators, or beneficiaries of any estate, if such trust or estate had any direct or indirect interest material to it in such Entity or in any property with respect to which Reserves Information was estimated or audited.

(j) Contingent Fee. Were engaged by such Entity to estimate or audit Reserves Information pursuant to any agreement, arrangement, or understanding whereby the remuneration or fee paid by such Entity was contingent upon, or related to, the results or conclusions reached in estimating or auditing such Reserves Information.

The independence of consulting Reserves Estimators and consulting Reserves Auditors, and the independence of any firm of petroleum consultants of which such individuals are stockholders, proprietors, partners, or employees, shall not be considered impaired merely because other petroleum engineering and related services were performed (i) for such Entity or any officer, director, principal stockholder, or other person affiliated therewith or (ii) in regard to any property with respect to which Reserves Information was estimated or audited, provided, however, that such other services must have been of a type normally rendered by the petroleum engineering profession and should be clearly disclosed in all reports relating to independent audits of, or reports containing, Reserves Information.


4.4	Requirement of Objectivity for Reserves Auditors Internally Employed by Entities

Reserves Auditors who are internally employed by an Entity should be empowered by the Entity to be objective with respect to such Entity if such Reserves Auditors audit Reserves Information relating to such Entity which purports to have been estimated or audited in accordance with these Standards.


4.5	Standards of Objectivity for Reserves Auditors Internally Employed by Entities

Reserves Auditors internally employed by an Entity would normally be considered to be in a position of objectivity with respect to such Entity if, during the time period in which Reserves Information was audited, such Reserves Auditors:

(a) Accountability to Management. Were assigned to an internal-audit group which was (i) accountable to Senior level management and/or the board of directors of such Entity and (ii) separate and independent from the operating and investment decision-making process of such Entity.

(b) Freedom to Report Irregularities. Were granted complete and unrestricted freedom to report, to one or more of the principal executives and/or the board of directors of such Entity, any substantive or procedural irregularities of which such Reserves Auditors became aware during their audit of Reserves Information pertaining to such Entity. Certain regulatory guidelines may require, or at least suggest, that such reporting by an internal auditor or auditing group be routinely made directly and exclusively to a board of directors, a board committee, or one or more of the members of the entity management team. It may further be appropriate to consider that internal reserves auditors and their supervisors, if any, be excluded from any reserves-based compensation incentive plans or the budget allocation processes of the entity. If reserves-based compensation incentive plans for internal reserves evaluators or auditors,

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supervisors, or management exist within the entity, then such incentive plans should be clearly disclosed in any reserves reporting external to the entity. Further disclosures may be appropriate in any circumstance(s) where an internal Reserves Auditor and the Entity Reserves Estimator(s) have been unable to reach agreement within the prescribed tolerances for a single property or group of properties.


4.6	Requirement of Confidentiality

Reserves Estimators and Reserves Auditors, and any firm of petroleum consultants of which such individuals are stockholders, proprietors, partners, or employees, should retain in strictest confidence Reserves Information and other data and information furnished by, or pertaining to, an Entity, and such Reserves Information, data, and information should not be disclosed to others without the prior consent of such Entity. This practice should be followed whether or not a confidentiality agreement has been executed.

Article V — Standards for Estimating Reserves and Other Reserves Information


5.1	General Considerations in Estimating Reserves Information

Reserves Information may be estimated through the use of generally accepted geological and engineering methods that are consistent with both these Standards and any statutory and regulatory provisions that are applicable to such Reserves Information, in accordance with its intended use. In estimating Reserves Information for a property or group of properties, Reserves Estimators will determine the geological and engineering methods to be used in estimating Reserves Information by considering (i) the sufficiency and reliability of the database; (ii) the stage of development; (iii) the performance history; (iv) their experience with respect to such property or group of properties, and with respect to similar properties; and (v) the significance of such property or group of properties to the aggregate oil and gas properties and interests being estimated or evaluated. The report as to Reserves Information should set forth information regarding the manner in which, and the assumptions pursuant to which, such report was prepared. Such disclosure should include, where appropriate, definitions of the significant terms used in such report; the geological and engineering methods and measurement base used in preparing the Reserve Information and the source of the data used with regard to ownership interests, oil and gas production and other performance data; costs of development, operations, and abandonment; product prices; and agreements relating to current and future operations, transportation, and sales of production. Reference is made herein to the Petroleum Reserves and Resources Classification, Definitions and Guidelines jointly published in 2007 by SPE, the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE), hereinafter denoted as the SPE 2007 Definitions. However, these Standards apply regardless of the specified system being employed in the evaluation.


5.2	Adequacy of Database in Estimating Reserves Information

The sufficiency and reliability of the database is of primary importance in the estimation of reserves and other Reserves Information. The type and extent of the data required will necessarily vary in accordance with the methods employed to estimate reserves and other Reserves Information. In this regard, information must be available with respect to each property or group of properties as to ownership and fiscal terms, marketing arrangements (including product prices), operating interests, and expense interests and revenue interests and future changes in any of such interests that, based on current circumstances, are expected to occur. Additionally, if future net revenue from reserves, or the present value of such future net revenue, is to be estimated, the database should include, with respect to each property or group of properties, estimated future expenditures for capital required in field development, capital for continued production maintenance, including but not limited to workovers and compression costs, operating costs, taxes, fees, transportation charges, and ultimate dismantlement costs, if appropriate. The foregoing is not intended as a complete listing of all items required for consideration in the estimation of reserves and reserves information.

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5.3	Estimating Reserves

The acceptable methods for estimating reserves include (i) the volumetric method, (ii) evaluation of the performance history, (iii) development of a mathematical model through consideration of material balance and computer simulation techniques, and (iv) analogy to other reservoirs if geographic location, formation characteristics, or similar factors render such analogy appropriate. In estimating reserves, Reserves Estimators should utilize the particular methods, and, if possible, combinations of a number of methods which, in their professional judgment, are most appropriate given (i) the geographic location, reservoir rock and fluid characteristics, and nature of the property or group of properties with respect to which reserves are being estimated; (ii) the amount and quality of available data; and (iii) the significance of such property or group of properties in relation to the oil and gas properties with respect to which reserves are being estimated. For all methodologies, the current reservoir conditions, such as pressures and fluid contacts, must be given consideration, as these may vary with time over the producing life of the property. Any or all of the methods identified above may need adaptation to conform to the reserves definitions that are applicable to the purpose of the estimate. In no event should the result of two or more methodologies be averaged to provide an estimate of reserves.


5.4	Estimating Reserves by the Volumetric Method

Estimating reserves in accordance with the volumetric method involves estimation of petroleum in place based upon review and analysis of such documents and information as (i) ownership and development maps; (ii) geological maps and models; (iii) openhole and cased-hole well logs and formation tests; (iv) relevant reservoir, fluid, and core data; (v) relevant seismic data and interpretations; and (v) information regarding the existing and planned completion of oil and gas wells and any production performance thereof. An appropriately estimated recovery efficiency is applied to the resulting oil and gas in place quantities in order to derive estimated original reserves. The unmodified term “reserves” is applicable to remaining quantities of petroleum, net of cumulative production, at any effective reporting date. The estimated recovery efficiency may also vary as a function of the appropriate reserves classification.


5.5	Estimating Reserves by Analyzing Performance Data

For reservoirs with respect to which performance has disclosed reliable production trends, reserves may be estimated by analysis of performance histories and projections of such trends. These estimates may be primarily predicated on an analysis of the rates of decline in production and on appropriate consideration of other performance parameters including, but not limited to, reservoir pressures, oil/water ratios, gas/oil ratios, and gas/liquid ratios. Particular attention should be given to the utilization of proprietary or commercial software programs that employ various types of mathematical routines to assist in the projection of future production rates or pressure trends. Professional judgment and experience, perhaps derived from appropriate analogies, should always be used in confirming mathematically derived projections.


5.6	Estimating Reserves by Using Mathematical Models (Reservoir Simulation)

Reserves and future production performance can be estimated through a combination of detailed geological and reservoir engineering studies and mathematical or computer simulation models. The validity of the mathematical simulation models is enhanced by the degree to which the calculated history matches the performance history, particularly at individual well locations. Where performance history is unavailable, special consideration should be given to determining the sensitivity of the calculated ultimate recoveries to the data that are the most uncertain. After making such sensitivity determinations, the ultimate recovery should be based on computed results using a combination of input parameters appropriate for the classification of reserves assigned. Again, the user is advised to exercise caution in accepting results produced through use of proprietary or commercial software without a full understanding of the internal mathematical algorithms and correlations.

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5.7	Estimating Reserves by Analogy to Comparable Reservoirs

If performance trends have not been established with respect to oil and gas production, future production rates and reserves may be estimated by analogy to reservoirs in the same formation and in the same geological environment having similar reservoir rock and fluid characteristics, drive mechanisms, and established performance trends. Care should be taken to recognize current reservoir rock and fluid characteristics and conditions (particularly the stage of depletion), since these can vary substantially during the producing life of any property and could affect the validity of the analogy employed. The choice and selection of acceptable analogs for reserves classification may be described in certain regulatory reporting applications.


5.8	Categorization of Reserves

Reserves must be categorized according to the level of certainty that they will be recovered. To guide the categorization of reserves, Reserves and Resource Definitions have been promulgated by various regulatory bodies and professional organizations throughout the world. Most such Definitions allow for different categories of reserves depending on the level of certainty associated with the reserves estimate. The highest category of reserves in many systems is “Proved Reserves,” which require the highest degree of confidence. Lower categories of unproved reserves, such as “Probable” or “Possible,” imply decreasing standards of certainty. Proved plus Probable reserves (2P) may represent the best estimate for many purposes, including regulatory reporting in some countries. When presenting a set of reserves quantities, the Reserves Estimator should always identify the Definitions under which those reserves were determined.

Different categories of reserves are used for different purposes. Proved reserves are always included in reports used for financial reporting and lending; however, the incorporation of both Proved and Probable reserves is increasingly becoming common in regulatory and financial reporting. Many, if not most, Entities and other users of Reserves Information routinely rely upon a recognition of all reserves categories for virtually all related business decisions.

The SPE 2007 Definitions contain a general requirement that Proved reserves have a “reasonable certainty” of being recovered. Other, more specific, criteria must also be met for reserves to be classified as Proved. The definition for Probable reserves is less stringent, requiring that a general test of “more likely than not” be satisfied. Possible reserves are those unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than Probable reserves.


5.9	Deterministic and Probabilistic Methods of Estimating Reserves

Under the SPE 2007 Definitions, reserves estimates may be prepared using either deterministic or probabilistic methods. With the deterministic method, the Reserves Estimator selects a single value for each parameter to be used in the calculation of reserves. The discrete value for each parameter is selected based on the estimator’s opinion of the value that is most appropriate for the corresponding reserves classification.

With the probabilistic method, the full range of possible values is described for each parameter. A mathematical technique, such as Monte Carlo Simulation (being one of several techniques), is then employed to perform a large number of random, repetitive calculations to generate a range of possible outcomes for the reserves and their associated probability of occurrence. Care should be given to all parameter values chosen but particularly for the endpoints of the relevant parameters to ensure that the possible outcomes generated are reasonable.

In principle, the two methods employ comparable calculation techniques. Conceptually, a deterministic estimate is a single value taken from a range of possible reserves values that can be expressed by a probabilistic analysis.

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For proved reserves, the SPE 2007 Definitions specify that there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate if probabilistic methods are used. Similarly, the definitions specify that there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves. And finally, there should be at least a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves.

It should be noted that the probability distribution of reserves values associated with the aggregation of a number of individual entities may be different from the arithmetic sum of the probability distributions for those entities. As the number of entities increases, the spread between the tails of the aggregated probability distribution decreases with respect to the spread observed for the arithmetic sum. In general, however, the arithmetic sum of a set of mean estimates will equal the mean of a probabilistic sum of such estimates. The aggregation method employed should be appropriate to the use of the results. Without specific regulatory guidance, the SPE 2007 Definitions recommends that reported reserves should not be based on probabilistic models beyond the field, property, or project level and that further aggregation be by arithmetic summation by reserves category. In all cases, the aggregation method and any additional conditions should be clearly stated.


5.10	Estimated Future Rates of Production

Future rates of oil and gas production may be estimated by extrapolating production trends where such trends have been established. If production trends have not been established, future rates of production may be estimated by analogy to the respective rates of production of reservoirs in the same geographic area having similar geological features, reservoir rock, drive mechanism, and fluid characteristics. If there are not available either (i) production trends from the property or group of properties with respect to which reserves are being estimated or (ii) rates of production from similar reservoirs, the estimates of future rates of production may be predicated on an assumed future decline rate that takes into proper consideration the cumulative oil and gas production that is estimated to occur prior to the predicted decline in such production in relation to the estimated ultimate production. Reservoir simulation is also an accepted method of estimating future rates of production. Irrespective of the method used, however, proper consideration should be given to (i) the producing capacities of the wells; (ii) the number of wells to be drilled in the future, together with the proposed times when such are to be drilled and the structural positions of such wells; (iii) the energy inherent in, or introduced to, the reservoir; (iv) the estimated ultimate recovery; (v) future remedial work to be performed; (vi) the scheduling of future well abandonments; (vii) normal downtime which may be anticipated; and (viii) artificial restriction of future production rates that is attributable to statutory and regulatory provisions, purchaser proration, marketing limitations, and other factors.


5.11	Estimating Other Reserves Information

A Reserves Estimator often estimates Reserves Information other than reserves and future rates of production in order to make his or her report more useful. Reserves net to the interests appraised are estimated using the Entity’s ownership interest in the property or group of properties, or in the production therefrom, with respect to which reserves were estimated. The nature of the ownership interest of the Entity may be established or affected by any number of arrangements, which the Reserve Estimator must take into account. Estimated future revenues are calculated from the estimated future rates of production by applying the appropriate sales prices furnished by the Entity or by using such other pricing levels as may be required by statutory and regulatory provisions that are applicable to such report in accordance with its intended use. Where appropriate, the Reserves Estimator deducts from such future revenues items such as (i) any existing production or severance taxes; (ii) taxes levied against property or production; (iii) estimates of future operating costs; (iv) estimates of any future development; equipment, or other significant capital expenditures required for the production of the reserves; and (v) net costs of abandonment. Such deductions normally include various overhead and management

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charges. For some purposes, it is desirable to subtract income taxes and other governmental levies in estimating future net revenues.

The foregoing may need to be modified to employ the “economic interest” method in the estimation of reserves (and reserves information) owned or controlled by an entity through a Production Sharing Agreement or other various forms of contracts or licensing agreements, as may be applicable. Legal advice may be critical to the full understanding of specific contract language affecting the right to report reserves in compliance with various regulatory bodies.

In estimating future net revenues, the Reserves Estimator should consider, where appropriate, any known or likely changes (i) from historical operating costs, (ii) from current estimates of future capital expenditures, and (iii) in other factors which may affect estimated limits of economic production.

Article VI — Standards for Auditing Reserves and Other Reserves Information


6.1	The Concept of Auditing Reserves and Other Reserves Information

An audit is an examination of Reserves Information that is conducted for the purpose of expressing an opinion as to whether such Reserves Information, in the aggregate, is reasonable and has been estimated by qualified individuals and presented in conformity with generally accepted petroleum engineering and evaluation principles and in compliance with the relevant reserves definitions. (See expanded definition of a reserves audit and types of Reserves Reports in Section 2.2).

As discussed in Section 1.3, the estimation of reserves and other Reserves Information is an imprecise science due to the many unknown geological and reservoir factors that can only be estimated through sampling techniques. Since reserves are therefore only estimates, they cannot be audited for the purpose of verifying exactness. Instead, Reserves Information is audited for the purpose of reviewing in sufficient detail the policies, procedures, methods, and data used by an Entity in estimating its Reserves Information so that the Reserves Auditors may express an opinion as to whether, in the aggregate, the Reserves Information furnished by such Entity is reasonable within established and predetermined tolerances and has been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles and the controlling reserves definitions.

The methods and procedures used by an Entity, and the Reserves Information it furnishes, must be reviewed in sufficient detail to permit the Reserves Auditor, in his or her professional judgment, to express an opinion as to the reasonableness of such Entity’s Reserves Information. In some cases, the auditing procedure may require independent estimates of Reserves Information for some or all properties. The desirability of such re-estimation will be determined by the Reserves Auditor exercising his or her professional judgment in arriving at an opinion as to the reasonableness of the Entity’s Reserves Information.

There may be some instances in which the Reserves Auditor cannot issue an unqualified report attesting to “reasonable” agreement in the aggregated Reserves Information compiled by the Entity. In such circumstances, the Entity may be requested to review and revise certain portions of its Reserves Information in a joint effort to produce an aggregated result within the predetermined tolerances comprising “reasonableness.” Failure to do so may result in a qualified report containing full disclosure of the inability to reach the desired result.


6.2	Limitations on Responsibility of Reserves Auditors

Since the primary responsibility for estimating and presenting Reserves Information pertaining to an Entity is with the management of such Entity, the responsibility of Reserves Auditors is necessarily limited to any opinion they express with respect to such Reserves Information. In discharging such responsibility, Reserves Auditors may accept, generally without independent verification, information and data furnished by the Entity with respect to ownership terms and interests, oil and gas production, historical costs of operation and development, product prices, agreements relating to current and future

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operations and sales of production, and other specified matters. If during the course of the audit, however, questions arise as to the accuracy or sufficiency of any information or data furnished by the Entity, the Reserves Auditor should not rely on such information or data unless such questions are resolved or the information or data are independently verified. If Reserves Information is used for financial accounting purposes, certain basic data would ordinarily be tested by an Entity’s independent public accountants in connection with their examination of the Entity’s financial statements. Such basic data would include information such as the property interests owned by the Entity, historical production data, and the prices, costs, and discount factors used in valuations of reserves. Reserves Auditors should, however, review estimates of major expenditures for development and equipment and any major differences between historical operating costs and estimated future operating costs.


6.3	Understanding Among an Entity, Its Independent Public Accountants (Where Applicable), and the Reserves Auditors

An understanding should exist among an Entity, its independent public accountants, where applicable, and the Reserves Auditors with respect to the nature of the work to be performed by the Reserves Auditors. Irrespective of whether the Reserves Auditors are consultants or internally employed by the Entity, the understanding between the Entity and the Reserves Auditors should include at least the following:

(a) Availability of Reserves Information. The Entity will provide the Reserves Auditors with (i) all existing Reserves Information prepared by such Entity, (ii) access to all basic data and documentation pertaining to the oil and gas properties of such Entity, (iii) access to all personnel of such Entity who might have information relevant to the audit of such Reserves Information, and (iv) the right to use additional nonconfidential information available to the auditor from other reliable sources.

(b) Performance of Audit. The Reserves Auditors will (i) study and evaluate the appropriateness of the methods and procedures used by the Entity in estimating and documenting its Reserves Information; (ii) review the reserves definitions and classifications used by such Entity; (iii) test and evaluate the Reserves Information of such Entity and the underlying data to the extent considered necessary by the Reserves Auditors; and (iv) express an opinion as to the reasonableness, in the aggregate, of such Entity’s Reserves Information.

(c) Availability of Audit Report to Independent Public Accountants. The Reserves Auditors will, upon written request, (i) permit their audit report to be provided to the independent public accountants of the Entity, when appropriate, for use in their examination of its financial statements and (ii) be available to discuss their audit report with such independent public accountants or others as authorized by the Entity.

(d) Coordination Between Reserves Auditors and Independent Public Accountants. The Reserves Auditors and the Entity’s independent public accountants will coordinate their efforts and agree on the records and data of the Entity to be reviewed by each, where such coordination is necessary.

In the case of an audit to be conducted by consulting Reserves Auditors, it is preferable that such understanding be documented, such as through an engagement letter between the Entity and the consulting Reserves Auditors.


6.4	Procedures for Auditing Reserves Information

Irrespective of whether the Reserves Information pertaining to an Entity is being audited by consulting Reserves Auditors or Reserves Auditors internally employed by such Entity, the audit should be conducted in accordance with the following procedures:

(a) Proper Planning and Supervision. The audit should be adequately planned, and assistants, if any, should be properly supervised. Clear paths of communication by the Reserves Auditors with all

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relevant individuals shall be established along with unrestricted access to pertinent data, work papers, and Reserves Information to be audited during normal business hours.

(b) Early Appointment of Reserves Auditors. Where appropriate, early appointment of Reserves Auditors is advantageous to both the Entity and the Reserves Auditors. Early appointment enables the Reserves Auditors to plan their work so that it may be done expeditiously and to determine the extent to which such can be completed prior to the balance sheet date. Preliminary work by the Reserves Auditors benefits the Entity by facilitating the efficient and expeditious completion of the audit of such Entity’s Reserves Information.

(c) Disclosure of the possibility of a Qualified Audit Opinion. Before accepting an engagement, Reserves Auditors should ascertain whether circumstances are likely to permit an unqualified opinion with respect to an Entity’s Reserves Information and, if such will not, they should discuss with such Entity (i) the possible necessity of their rendering a qualified opinion and (ii) the possible remedies to the circumstances giving rise to the potential qualification of such opinion.

(d) Interim Audit Procedures. Many audit tests can be conducted at almost any time during the year. In the course of interim work, the Reserves Auditors make tests of the Entity’s methods, procedures, and controls to determine the extent to which such are reliable. It is acceptable practice for the Reserves Auditors to complete substantial parts of an audit examination at interim dates.

When a significant part of an audit is completed during the year and the Entity’s methods, procedures, and controls are found to be effective, the year-end audit procedure may primarily consist of an evaluation of the impact of new data. The Reserves Auditors must nevertheless be satisfied that the procedures and controls are still effective at the year’s end and that new discoveries, recent oil and gas production, and other recent information and data have been taken into account. Reserve Auditors would not be required to retest the database pertaining to an Entity’s properties and interests unless their inquiries and observations indicate that conditions have changed significantly.

(e) General Matters To Be Reviewed With Respect to Reserves Information. An audit of the Reserves Information pertaining to an Entity generally should include a review of (i) the policies, procedures, controls, documentation, and guidelines of such Entity with respect to the estimation, review, and approval of its Reserves Information; (ii) the qualifications and independence of Reserves Estimators internally employed by such Entity; (iii) ratios of such Entity’s reserves to annual production for, respectively, oil, gas, and natural gas liquids; (iv) historical reserves and revision trends with respect to the oil and gas properties and interests of such Entity; (v) the ranking by size of properties or groups of properties with respect to estimates of reserves or the future net revenue from such reserves; (vi) the percentages of reserves estimated by each of the various methods set forth in Section 5.3 for estimating reserves; and (vii) the significant changes occurring in such Entity’s reserves, other than from production, during the year with respect to which the audit is being prepared.

(f) Evaluation of Internal Policies, Procedures, Controls, and Documentation. Reserves Auditors should review and evaluate the internal policies, procedures, controls, and documentation of an Entity to establish an understanding of the internal processes which such Entity uses in its reviews of existing Reserves Information. The internal policies, procedures and documentation to be reviewed with respect to an Entity should include (i) reserves definitions and classifications used by such Entity; (ii) such Entity’s policies pertaining to, and management involvement in, the review and approval of Reserves Information and changes therein; (iii) the frequency with which such Entity reviews existing Reserves information and documentation of the Reserves Information of such Entity, together with such Entity’s internal distribution thereof; (iv) the form, content, and basis for reliance thereon in determining the nature, extent, and timing of the audit tests to be applied in the examination of such Entity’s Reserves Information and other data and matters; and (v) the flow of data to and from such Entity’s reserves inventory system.

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(g) Testing for Compliance. Reserves Auditors should conduct tests and spot checks to confirm that (i) there is adherence on the part of an Entity’s internal Reserves Estimators and other employees to the policies, procedures, and controls established by such Entity and (ii) the data flowing into the reserves inventory system of such Entity is complete and consistent with other available records.

(h) Substantive Testing. In conducting substantive tests, Reserves Auditors should give priority to each property or group of properties of an Entity having (i) a large reserves value in relation to the aggregate properties of such Entity; (ii) a relatively large reserves value and major changes during the audit year in the Reserves Information pertaining to such property or group of properties; and (iii) a relatively large reserves value and a high degree of uncertainty in the Reserves Information pertaining thereto. The selection of properties for substantive testing shall be made independently by the Reserves Auditors. The amount of substantive testing performed with respect to particular Reserves Information of an Entity should depend on the assessment of (i) the general degree of uncertainty with respect to such Reserves Information, (ii) the evaluation of the internal policies, procedures, and documentation of such Entity, and (iii) the results of the compliance testing with respect to such Entity. Such substantive testing could therefore appropriately range from a limited number of tests selected by the Reserves Auditor to the complete estimation of Reserves Information with respect to a majority of an Entity’s reserves.


6.5	Records and Documentation With Respect to Audit

The Reserves Auditor should document, and maintain records with respect to, each audit of the Reserves Information of an Entity. Such documentation and records should include, among other things, a description of (i) the Reserves Information audited; (ii) the review and evaluation of such Entity’s policies, procedures, and documentation; (iii) the compliance testing performed with respect to such Entity; and (iv) the substantive tests performed in the course of such audit.


6.6	Forms of Unqualified Audit Opinions.

Acceptable forms of unqualified audit opinions for consulting Reserves Auditors and Reserves Auditors internally employed by Entities are attached to these Standards as, respectively, Exhibits “A” and “B.”

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Exhibit “A” — Illustrative Unqualified Audit
Opinion of Consulting Reserves Auditor*

(Date)

Entity

[Address]

Independent Public Accountants of Entity

[Address]

Gentlemen:

At your request, we have examined the estimates as of [dates] set forth in the accompanying table with respect to (i) the proved reserves of Entity, (ii) changes in such proved reserves during the period indicated, (iii) the future net revenue from such proved reserves, and (iv) the present value of such future net revenue. Our examination included such tests and procedures as we considered necessary under the circumstances to render the opinion set forth herein.

[A detailed description of the audit should be set forth.]

We are independent with respect to Entity as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

It should be understood that our above-described audit does not constitute a complete reserve study of the oil and gas properties of Entity. In the conduct of our report, we have not independently verified the accuracy and completeness of information and data furnished by Entity with respect to ownership interests, oil and gas production, historical costs of operation and development, product prices, agreements relating to current and future operations and sales of production, and (specify other information, data, and matters upon which reliance was placed). We have, however, specifically identified to you the information and data upon which we so relied so that you may subject such to those procedures that you consider necessary. Furthermore, if in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data.

Please be advised that, based upon the foregoing, in our opinion the above-described estimates of Entity’s proved reserves and other Reserves Information are, in the aggregate, reasonable within the established audit tolerance guidelines of (+ or -)[ ]% and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

(Insert, where appropriate and to the extent warranted by the Reserves Auditor’s examination, whether the Reserves Information is in conformity with specified governmental regulations.)

(Optional: This letter is solely for the information of Entity and for the information and assistance of its independent public accountants in connection with their review of, and report upon, the financial statements of Entity. This letter should not be used, circulated, or quoted for any other purpose without the express written consent of the undersigned or except as required by law.)

Very truly yours,

RESERVES AUDITOR


	By

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Exhibit “B” — Illustrative Unqualified Audit
Opinion of Reserves Auditor Internally
Employed by an Entity*

(Date)

Entity

[Address]

Independent Public Accountants of Entity

[Address]

Gentlemen:

I have examined the estimates as of [dates] set forth in the accompanying table with respect to (i) the proved reserves of Entity, (ii) changes in such proved reserves during the period indicated, (iii) the future net revenue from such proved reserves, and (iv) the present value of such future net revenue. My examination included such tests and procedures as I considered necessary under the circumstances to render the opinion set forth herein.

[A detailed description of the audit tests and procedures may be set forth.]

I meet the requirements of objectivity for Reserves Auditors internally employed by Entities as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

It should be understood that my above-described audit does not constitute a complete reserves study of the oil and gas properties of Entity. In the conduct of my report, I have not independently verified the accuracy and completeness of information and data furnished by other employees of Entity with respect to ownership interests, oil and gas production, historical costs of operation and development, development, product prices, agreements relating to current and future operations and sales of production, and [specify other information, data, and matters upon which reliance was placed]. I have, however, specifically identified to you the information and data upon which I so relied so that you may subject such to those procedures that you consider necessary. Furthermore, if in the course of my examination something came to my attention which brought into question the validity or sufficiency of any of such information or data, I did not rely on such information or data until I had satisfactorily resolved my questions relating thereto or had independently verified such information or data.

Please be advised that, based upon the foregoing, in my opinion the above-described estimates of Entity’s proved reserves and other Reserves Information are, in the aggregate, reasonable within the established audit tolerances of (+ or -)[ ]% and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

[Insert, where appropriate and to the extent warranted by the Reserves Auditor’s examination, whether the Reserves Information is in conformity with specified governmental regulations.]

Very truly yours,

RESERVES AUDITOR


	By

* If a Reserves Auditor is unable to give an unqualified opinion as to an Entity’s Reserves Information, the Reserves Auditor should set forth in his or her opinion the nature and extent of the qualifications to such opinion and the reasons therefore.

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PROSPECTUS SUMMARY		1
QR Energy, LP		1
Overview		1
Our Properties		2
Our Hedging Strategy		3
Our Business Strategies		4
Our Competitive Strengths		4
Our Principal Business Relationships		4
Our Relationship with the Fund		5
Our Relationship with Quantum Energy Partners		6
Formation Transactions and Partnership Structure		8
Ownership and Organizational Structure of QR Energy, LP		9
Management of QR Energy, LP		10
Principal Executive Offices and Internet Address		12
Summary of Conflicts of Interest and Fiduciary Duties		12
The Offering		15
Summary Historical and Pro Forma Financial Data		22
Non-GAAP Financial Measures		25
Summary Reserve and Pro Forma Operating Data		27
RISK FACTORS		29
Risks Related to Our Business		29
Risks Inherent in an Investment in Us		48
Tax Risks to Unitholders		61
USE OF PROCEEDS		66
CAPITALIZATION		67
DILUTION		68
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		70
General		70
Our Minimum Quarterly Distribution		72
Unaudited Pro Forma Available Cash for the Year Ended December 31, 2009 and the Twelve Months Ended September 30, 2010		74
Estimated Adjusted EBITDA for the Twelve Months Ending December 31, 2011		77
Assumptions and Considerations		81
Sensitivity Analysis		89
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS AND THE MANAGEMENT INCENTIVE FEE		93
Distributions of Available Cash		93
Operating Surplus and Capital Surplus		94
Capital Expenditures		96
Subordination Period		98
Distributions of Available Cash from Operating Surplus During the Subordination Period		99
Distributions of Available Cash from Operating Surplus After the Subordination Period		100
General Partner Interest and Management Incentive Fee		100
General Partner’s Right to Convert Management Incentive Fee into Class B Units		101
Distributions from Capital Surplus		105
Adjustment to the Minimum Quarterly Distribution and Target Distribution		106
Distributions of Cash Upon Liquidation		106
Adjustments to Capital Accounts		108
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA		109


MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		112
Overview		112
How We Conduct Our Business and Evaluate Our Operations		113
Historical and Pro Forma Financial and Operating Data		119
Pro Forma Results of Operations		120
Pro Forma Liquidity and Capital Resources		122
Pro Forma Quantitative and Qualitative Disclosure About Market Risk		125
Predecessor Results of Operations		127
Predecessor Liquidity and Capital Resources		131
Predecessor Contractual Obligations		134
Predecessor Quantitative and Qualitative Disclosure About Market Risk		134
Critical Accounting Policies and Estimates		136
Recently Issued Accounting Pronouncements		139
Internal Controls and Procedures		139
Inflation		140
Off-Balance Sheet Arrangements		140
BUSINESS AND PROPERTIES		141
Overview		141
Our Properties		141
Our Hedging Strategy		142
Our Business Strategies		143
Our Competitive Strengths		144
Our Principal Business Relationships		146
Our Relationship with the Fund		146
Our Relationship with Quantum Energy Partners		147
Properties		148
Oil Recovery Overview		155
Oil and Natural Gas Data and Operations — Partnership Properties		156
Oil and Natural Gas Data and Operations — Our Predecessor		161
Operations		161
Environmental Matters and Regulation		163
Other Regulation of the Oil and Natural Gas Industry		167
Employees		169
Offices		169
Legal Proceedings		169
MANAGEMENT		170
Management of QR Energy, LP		170
Directors and Executive Officers		172
Reimbursement of Expenses of Our General Partner		175
Executive Compensation		175
Compensation Discussion and Analysis		176
Compensation of Directors		178
Long-Term Incentive Plan		178
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		181
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		183
Distributions and Payments to Our General Partner and Its Affiliates		183
Agreements Governing the Transactions		188
Contracts with Affiliates		190
Review, Approval or Ratification of Transactions with Related Persons		192
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		193
Conflicts of Interest		193
Fiduciary Duties		201


DESCRIPTION OF THE COMMON UNITS		204
The Units		204
Transfer Agent and Registrar		204
Transfer of Common Units		204
THE PARTNERSHIP AGREEMENT		206
Organization and Duration		206
Purpose		206
Cash Distributions		206
Capital Contributions		206
Limited Voting Rights		207
Applicable Law; Forum, Venue and Jurisdiction		208
Limited Liability		209
Issuance of Additional Interests		210
Amendment of the Partnership Agreement		210
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets		212
Dissolution		213
Liquidation and Distribution of Proceeds		213
Withdrawal or Removal of Our General Partner		214
Transfer of General Partner Units		215
Transfer of Ownership Interests in Our General Partner		215
Assignment of Management Incentive Fee		215
Change of Management Provisions		216
Limited Call Right		216
Meetings; Voting		216
Status as Limited Partner		217
Non-Eligible Holders; Redemption		217
Indemnification		218
Reimbursement of Expenses		218
Books and Reports		219
Right to Inspect Our Books and Records		219
Registration Rights		219
UNITS ELIGIBLE FOR FUTURE SALE		220
MATERIAL TAX CONSEQUENCES		222
Taxation of QR Energy, LP		223
Tax Consequences of Unit Ownership		224
Tax Treatment of Operations		230
Disposition of Units		235
Uniformity of Units		237
Tax-Exempt Organizations and Other Investors		237
Administrative Matters		238
State, Local and Other Tax Considerations		241
INVESTMENT IN QR ENERGY, LP BY EMPLOYEE BENEFIT PLANS		242
UNDERWRITING		244
VALIDITY OF THE COMMON UNITS		249
EXPERTS		249
WHERE YOU CAN FIND MORE INFORMATION		249
FORWARD-LOOKING STATEMENTS		250
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A — FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF QR ENERGY, LP		A-1
APPENDIX B — GLOSSARY OF TERMS		B-1
APPENDIX C — MILLER AND LENTS, LTD SUMMARY OF JUNE 30, 2010 RESERVES		C-1


		Page

QR ENERGY, LP
Unaudited Pro Forma Condensed Financial Statements:
Introduction		F-2
Unaudited Pro Forma Condensed Balance Sheet as of September 30, 2010		F-4
Unaudited Pro Forma Condensed Statement of Operations for the Nine Months Ended September 30, 2010		F-5
Unaudited Pro Forma Condensed Statement of Operations for the Nine Months Ended September 30, 2009		F-6
Unaudited Pro Forma Condensed Statement of Operations for the Year Ended December 31, 2009		F-7
Notes to Unaudited Pro Forma Condensed Financial Statements		F-8
Historical Balance Sheet:
Report of Independent Registered Public Accounting Firm		F-14
Balance Sheet as of September 20, 2010 and September 30, 2010 (unaudited)		F-15
Note to Balance Sheet		F-16
QA HOLDINGS, LP
Unaudited Historical Consolidated Financial Statements as of September 30, 2010 and for the Nine Months Ended September 30, 2010 and 2009:
Consolidated Balance Sheets		F-17
Consolidated Statements of Operations		F-18
Consolidated Statements of Changes in Partners’ Capital		F-19
Consolidated Statements of Cash Flows		F-20
Notes to Unaudited Consolidated Financial Statements		F-21
Historical Consolidated Financial Statements as of December 31, 2008 and 2009 and for the Years Ended December 31, 2007, 2008 and 2009:
Report of Independent Registered Public Accounting Firm		F-37
Report of Independent Registered Public Accounting Firm		F-38
Consolidated Balance Sheets		F-39
Consolidated Statements of Operations		F-40
Consolidated Statements of Changes in Partners’ Capital		F-41
Consolidated Statements of Cash Flows		F-42
Notes to Consolidated Financial Statements		F-43
DENBURY PROPERTY ACQUISITION FINANCIALS
Historical Financial Statements of the Acquired Encore Properties for the Years Ended December 31, 2007, 2008 and 2009 and for the Three Months Ended March 31, 2009 and 2010:
Report of Independent Registered Public Accounting Firm		F-71
Statements of Revenues and Direct Operating Expenses		F-72
Notes to Statements of Revenues and Direct Operating Expenses		F-73
Historical Financial Statements of the Acquired Exco Properties for the Years Ended December 31, 2007 and 2008 and for the Period from January 1, 2009 to August 11, 2009:
Independent Auditor’s Report		F-76
Statements of Revenues and Direct Operating Expenses		F-77
Notes to Statements of Revenues and Direct Operating Expenses		F-78


	September 20, 2010			September 30, 2010
				(unaudited)

Assets
Cash	$	—		$	—

Total assets	$	—		$	—


Partners’ capital
Limited partners’ capital	$	999		$	999
General partners’ capital		1			1
Receivable from partners		(1,000	)		(1,000	)

Total partners’ capital	$	—		$	—


	For the Year Ended December 31,						For the Three Months Ended March 31,
	2007		2008		2009		2009		2010
							(Unaudited)


Natural gas, oil and natural gas liquids revenue	$	111,447	$	170,570	$	124,526	$	21,463	$	49,593
Direct operating expenses		30,575		38,234		40,803		7,495		13,707

Revenues in excess of operating expenses	$	80,872	$	132,336	$	83,723	$	13,968	$	35,886


	Period from
	January 1, 2009		Year Ended		Year Ended
	to August 11, 2009		December 31, 2008		December 31, 2007
	(In thousands)

Revenues
Oil and natural gas revenues	$	36,451	$	155,114	$	100,081

Direct operating expenses:
Lease operating expenses		10,524		17,875		11,668
Ad valorem and severance taxes		3,546		10,894		7,073
Total direct operating expenses		14,070		28,769		18,741

Excess of revenues over direct operating expenses	$	22,381	$	126,345	$	81,340


	Section 14.4	Certificate of Merger	A-83
	Section 14.5	Effect of Merger, Consolidation or Conversion	A-83

ARTICLE XV
RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS
	Section 15.1	Right to Acquire Limited Partner Interests	A-84

ARTICLE XVI
GENERAL PROVISIONS
	Section 16.1	Addresses and Notices; Written Communications	A-85
	Section 16.2	Further Action	A-86
	Section 16.3	Binding Effect	A-86
	Section 16.4	Integration	A-86
	Section 16.5	Creditors	A-86
	Section 16.6	Waiver	A-86
	Section 16.7	Third-Party Beneficiaries	A-86
	Section 16.8	Counterparts	A-87
	Section 16.9	Applicable Law; Forum, Venue and Jurisdiction	A-87
	Section 16.10	Invalidity of Provisions	A-87
	Section 16.11	Consent of Partners	A-88
	Section 16.12	Facsimile Signatures	A-88



Dated:		QR Energy, LP

Countersigned and Registered by:		By: QRE GP, LLC

, As Transfer Agent and Registrar		By:
		Name:

		Title:

		By:

		Name:

		Title: