As filed with the Securities and Exchange Commission on September 30, 2010

Registration No. 333-      

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

 

 

QR Energy, LP

(Exact name of registrant as specified in its charter)

 

 

5 Houston Center

1401 McKinney Street, Suite 2400

Houston, Texas 77010

(713) 452-2200

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

 

Gregory S. Roden

QRE GP, LLC

5 Houston Center

1401 McKinney Street, Suite 2400

Houston, Texas 77010

(713) 452-2200

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

Copies to:

 

 

 

 

 

Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.

 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  o

 

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

 

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

 

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

 

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

 

 

 

 

 

CALCULATION OF REGISTRATION FEE

 

 

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

PRELIMINARY PROSPECTUS

                    SUBJECT TO COMPLETION DATED SEPTEMBER 30, 2010

 

QR Energy, LP

     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. This is the initial public offering of our common units. No public market currently exists for our common units. We expect the initial public offering price to be between $      and $      per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “QRE”.

Investing in our common units involves risks. Please read “Risk Factors”

beginning on page 25.

 

These risks include the following:

 

 

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.

 

 

⁽¹⁾Excludes an aggregate structuring fee equal to     % of the gross proceeds of this offering, or approximately $     , payable to Wells Fargo Securities, LLC.

 

We have granted the underwriters a 30-day option to purchase up to an additional          common units on the same terms and conditions as set forth above if the underwriters sell more than           common units in this offering.

 

The underwriters expect to deliver the common units on or about          , 20  .

Prospectus dated          , 2010

 

 

[Area of Operations]

 

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TABLE OF CONTENTS

 

 

 

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          , 20  (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” and “Forward-Looking Statements.”

 

Industry and Market Data

 

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the information.

 

PROSPECTUS SUMMARY

	•	“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 and certain related entities;
	•	“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.

 

QR Energy, LP

 

Overview

 

Our Properties

																						Average Net
		Estimated Pro Forma																Standardized				Pro Forma
		Net Proved Reserves (MBoe)												% Oil and				Measure(1)				Production								Producing Wells
		Developed				Undeveloped				Total				NGLs				(in millions)				Boe/d				%				Gross				Net
Permian Basin			9,340				8,238				17,578				90	%		$	305.5				2,316				45	%			1,661				313
Ark-La-Tex			6,735				1,194				7,929				32	%			91.0				1,723				34	%			225				125
Mid-Continent			2,349				—				2,349				43	%			28.8				572				11	%			199				92
Gulf Coast(2)			2,114				—				2,114				55	%			48.9				516				10	%			14				4
Total			20,538				9,432				29,970				69	%		$	474.2				5,127				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.” 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 4% of our pro forma average net daily production for the six months ended 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.”

 

Our Hedging Strategy

 

Our 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 program; and
	•	Maintain a balanced capital structure to provide financial flexibility for acquisitions.

 

Our Competitive Strengths

	•	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.

 

Our Principal Business Relationships

 

Our Relationship with the Fund

 

Our Relationship with Quantum Energy Partners

 

Formation Transactions and Partnership Structure

	•	The Fund will contribute to us (i) specified oil and natural gas properties, certain wellbore assignments and an overriding oil royalty interest, which we refer to collectively as the “Partnership Properties,” and (ii) derivative contracts covering approximately 66% to 81% of our estimated future oil and natural gas production through 2014, based on production estimates in our reserve report dated June 30, 2010;
	•	We will issue to the Fund           common units and           subordinated units, representing an aggregate     % limited partner interest in us;
	•	We will issue to QRE GP, LLC           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 will receive net proceeds of $      million from the issuance and sale of           common units to the public (based on the midpoint of the price range set forth on the cover page of this prospectus), representing a     % limited partner interest in us, and we will use the net proceeds as described in “Use of Proceeds”;
	•	We expect to borrow approximately $225 million under a new $500 million revolving credit facility, and we will use the proceeds as described in “Use of Proceeds”;
	•	We anticipate that we will assume a portion of the Fund’s debt that currently burdens the Partnership Properties. If we assume any such debt, 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. Please read “Use of Proceeds”;
	•	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.

 

Ownership and Organizational Structure of QR Energy, LP

		Ownership
		Interest
Common Units held by the public				%
Common Units held by the Fund				%
Subordinated Units held by the Fund				%
General Partner Units				%
Total

(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

 

Principal Executive Offices and Internet Address

 

Summary of Conflicts of Interest and Fiduciary Duties

	•	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.

 

The Offering

Common units offered by us		common units or           common units if the underwriters exercise in full their option to purchase additional common units.
Units outstanding after this offering		common units and          subordinated units, representing     % and     %, 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 intend to use the estimated net proceeds of approximately $      million from this offering, based upon the assumed initial public offering price of $      per common unit (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, structuring fees and expenses, together with borrowings of approximately $225 million under our new revolving credit facility, to make a cash distribution to the Fund. If we assume some portion 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,” we will reduce the amount of the 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. 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.”
Cash distributions		We expect to make a minimum quarterly distribution of $      per unit per quarter on all common, subordinated, Class B, if any, and general partner units ($      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.”
		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.
		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 at 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 $      per common unit (or 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.” Payment of the management incentive fee will reduce cash available for distribution to our unitholders.
		The amount of unaudited pro forma available cash generated during the twelve-month period ended June 30, 2010 would have been approximately $51.0 million, which would have been sufficient to allow us to pay approximately     % of the minimum quarterly distribution on our common units and general partner units and     % of the minimum quarterly distribution on our subordinated units. For a calculation of our ability to make distributions to our unitholders based on our pro forma results for the year ended December 31, 2009 and the twelve months ended June 30, 2010, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

		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 $      per unit on all common, subordinated and general partner units. Please read “Our Cash Distribution Policy and Restrictions on Distributions — Minimum Estimated Cash Available for Distribution for the Twelve-Month Period Ending December 31, 2011.”
Subordinated units		Following 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 $      per unit ($      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 and general partner 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 on the common units have been eliminated; and
		• the removal of our general partner other than for cause, provided that the units held by our general partner and its affiliates are not 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 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 is an amount equal to the sum of (i) 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 (ii) 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 agreed upon by our general partner and the conflicts committee of our general partner’s board of directors. This 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 fully-engineered third-party 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 permitted.
		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’’) 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.”
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 a time when it has received all or any portion of the management incentive fee for each of the immediately preceding four consecutive quarters to convert into Class B units up to 80% of the management incentive fee for a particular 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 in the immediately preceding two calendar quarters, 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 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 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.”
Issuance of additional units		We can issue an unlimited number of additional units, including units that are senior to the common units in right of distributions, liquidation and voting, on terms and conditions determined by our general partner, without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”
Limited voting rights		Our general partner will manage us and operate our business. Unlike stockholders of a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding 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 our common and subordinated units and will therefore be able to prevent the removal of our general partner. Please read “The Partnership Agreement — Limited Voting Rights.”
Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. Upon the consummation of this offering, our general partner, its owners and their affiliates, including the Fund, will own an aggregate of     % of our common and 100% of our subordinated units. Please read “The Partnership Agreement — Limited Call Right.”
Eligible Holders and redemption		Only Eligible Holders will be entitled to receive distributions or be allocated income or loss from us. 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 a transferee or unitholder, as the case may be, does not properly complete the transfer application or recertification, for any reason, such transferee or unitholder will have no right to receive any distributions or allocations of income or loss on its common units or to vote its units on any matter, and we will have the right to redeem such units at a price which is equal to the lower of the transferee’s or unitholder’s purchase price or 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” and “The Partnership Agreement — Non-Eligible Holders; Redemption.”
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     % of the cash distributed to such unitholders with respect to that period. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for 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.”
Listing and trading symbol		We intend to apply to list our common units on the New York Stock Exchange under the symbol “QRE”.

 

Summary Historical and Pro Forma Financial Data

	•	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           common units,           subordinated units and $      million in cash (assuming the midpoint of the price range set forth on the cover page of this prospectus and including approximately $225 million borrowed under our new credit facility, as described below);
	•	the issuance to QRE GP, LLC of           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           common units in this offering and the application of the net proceeds as described in “Use of Proceeds”; and
	•	our borrowing of approximately $225 million under our new $500 million revolving credit facility and the application of the proceeds as described in “Use of Proceeds.”

																						QR Energy, LP
		Our Predecessor																				Pro Forma
														Six Months Ended								Year Ended				Six Months
		Year Ended December 31,												June 30,								December 31,				Ended June 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			$	30,823			$	88,172			$	76,904			$	51,055
Processing fees and other			6,689				32,541				3,608				2,512				2,820				—				—
Total revenues		$	171,317			$	281,070			$	72,801			$	33,335			$	90,992			$	76,904			$	51,055
Operating costs and expenses:
Lease operating		$	77,767			$	90,424			$	33,328			$	14,821			$	28,599			$	23,783			$	11,655
Production taxes			12,954				14,566				7,587				3,089				6,098				5,764				2,457
Transportation and processing			4,728				26,189				3,926				1,832				2,560				1,534				731
Impairment of oil and gas properties(1)			—				451,440				28,338				28,338				—				17,951				—
Depreciation, depletion and amortization			42,889				49,309				16,993				9,838				19,241				29,012				14,086
Accretion of asset retirement obligations			2,751				3,004				3,585				1,715				1,455				524				338
Fund management fees(2)			11,482				12,018				12,018				6,009				4,970				—				—
General and administrative and other			20,677				14,852				19,461				7,185				11,883				11,268				7,248
Bargain purchase option			—				—				(1,200	)			(1,200	)			(1,020	)			—				—
Total operating costs and expenses		$	173,248			$	661,802			$	124,036			$	71,627			$	73,786			$	89,836			$	36,515
Income (loss) from operations		$	(1,931	)		$	(380,732	)		$	(51,235	)		$	(38,292	)		$	17,206			$	(12,932	)		$	14,540
Other income (expenses):
Interest income		$	978			$	617			$	37			$	29			$	22			$	—			$	—
Realized gains (losses) on derivative contracts			6,861				(34,666	)			47,993				32,204				2,913				30,441				1,277
Unrealized gains (losses) on derivative contracts			(157,250	)			169,321				(111,113	)			(70,588	)			44,933				(70,477	)			19,694
Interest expense			(17,359	)			(13,034	)			(3,753	)			(1,991	)			(12,906	)			(7,688	)			(3,842	)
Other			7				(10,039	)			2,657				2,089				299				—				—
Total other income (expense)		$	(166,763	)		$	112,199			$	(64,179	)		$	(38,257	)		$	35,261			$	(47,724	)		$	17,129
Net income (loss)		$	(168,694	)		$	(268,533	)		$	(115,414	)		$	(76,549	)		$	52,467			$	(60,656	)		$	31,669
Other Financial Data:
Adjusted EBITDA		$	50,557			$	78,316			$	48,331			$	35,892			$	41,114			$	73,595			$	36,177
Cash Flow Data:
Net cash provided by (used in):
Operating activities		$	24,839			$	75,282			$	71,140			$	41,154			$	15,858
Investing activities			(72,953	)			(137,161	)			(61,691	)			(59,730	)			(904,215	)
Financing activities			89,890				30,240				(13,328	)			12,131				890,405

(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.

														QR Energy, LP
		Our Predecessor												Pro Forma
		As of December 31,								As of June 30,				As of June 30,
		2008				2009				2010				2010
		(in thousands)
Balance Sheet Data:
Working capital		$	67,139			$	(74	)		$	15,965			$	13,206
Total assets			304,937				226,770				1,200,737				415,357
Total debt			88,750				86,450				547,668				225,000
Non-controlling interests			133,978				14,733				489,761				—
Partners’ capital			5,957				(1,421	)			17,072				181,494

 

Non-GAAP Financial Measures

	•	Plus:

	•	Interest expense;
	•	Depletion, depreciation and amortization;
	•	Accretion of asset retirement obligations;
	•	Unrealized losses on 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 derivative contracts.

	•	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.

																						QR Energy, LP
		Our Predecessor																				Pro Forma
														Six Months Ended								Year Ended				Six Months
		Year Ended December 31,												June 30,								December 31,				Ended June 30,
		2007				2008				2009				2009				2010				2009				2010
		(in thousands)
Net income (loss)		$	(168,694	)		$	(268,533	)		$	(115,414	)		$	(76,549	)		$	52,467			$	(60,656	)		$	31,669
Unrealized (gains) losses on derivative contracts			157,250				(169,321	)			111,113				70,588				(44,933	)			70,477				(19,694	)
Depletion, depreciation and amortization			42,889				49,309				16,993				9,838				19,241				29,012				14,086
Accretion of asset retirement obligations			2,751				3,004				3,585				1,715				1,455				524				338
Interest income			(978	)			(617	)			(37	)			(29	)			(22	)			—				—
Interest expense			17,359				13,034				3,753				1,991				12,906				7,688				3,842
Impairment expense			—				451,440				28,338				28,338				—				17,951				—
General and administrative expense in excess of the administrative services fee			—				—				—				—				—				8,599				5,936
Adjusted EBITDA		$	50,577			$	78,316			$	48,331			$	35,892			$	41,114			$	73,595			$	36,177

		Our Predecessor
														Six Months Ended
		Year Ended December 31,												June 30,
		2007				2008				2009				2009				2010
Net cash provided by (used in) operating activities		$	24,839			$	75,282			$	71,140			$	41,154			$	15,858
(Increase) decrease in working capital			3,342				9,010				(24,941	)			(4,744	)			19,773
Purchase of derivative contracts			7,546				2,694				—				—				—
Amortization of costs of derivative contracts			—				(7,981	)			(1,219	)			(603	)			—
Interest (income) expense, net			14,843				9,929				6,038				3,276				4,330
Unrealized (gains) losses on investment in marketable equity securities			—				(5,640	)			5,640				5,640				—
Loss on disposal of furniture, fixtures and equipment			—				—				(723	)			(4	)			(575	)
Realized losses on investment in marketable equity securities			—				(1,968	)			(5,246	)			(5,246	)			—
Proceeds from sales of marketable equity securities			—				—				(6,233	)			(6,233	)			—
Gain on sale/acquisition of properties			—				—				1,200				1,200				1,020
Equity in earnings of Ute Energy, LLC			7				(3,010	)			2,675				1,452				708
Adjusted EBITDA		$	50,577			$	78,316			$	48,331			$	35,892			$	41,114

 

Summary Reserve and Pro Forma Operating Data

		Partnership Properties
		As of				As of
		December 31,				June 30,
		2009				2010
Estimated Proved Reserves:
Estimated net proved reserves:
Oil (MBbls)			20,108				19,125
NGLs (MBbls)			1,629				1,446
Natural gas (MMcf)			56,330				56,394
Total (MBoe)(1)			31,125				29,970
Proved developed (MBoe)			22,127				20,538
Proved undeveloped (MBoe)			8,998				9,432
Proved developed reserves as a percentage of total proved reserves			71	%			69	%
Standardized measure (in millions)(2)		$	360.1			$	474.2
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.
(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 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 derivative contracts, please read

		“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Liquidity and Capital Resources — Partnership Derivative Contracts.”
(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.

		QR Energy, LP
		Pro Forma
		Year Ended				Six Months Ended
		December 31,				June 30,
		2009				2009				2010
Net Production:
Total production (MBoe)			1,927				972				936
Average production (Boe/d)			5,280				5,323				5,127
Average Sales Price per Boe(1)		$	39.91			$	33.84			$	54.56
Average Unit Costs per Boe:
Oil and natural gas production expenses		$	12.34			$	11.71			$	12.46
Production taxes		$	2.99			$	1.90			$	2.63
Fund management fees		$	—			$	—			$	—
General and administrative expenses		$	5.85			$	6.04			$	7.75
Depletion, depreciation and amortization		$	15.06			$	15.05			$	15.05

(1)		Pro forma average sales prices per Boe do not include gains or losses on derivative contracts. Because the derivative contracts to be contributed to us have been commingled with the properties retained by our predecessor, the pro forma information associated with these 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 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 derivative contracts. Accordingly, we have omitted the effects of derivative contracts from our pro forma average sales prices per Boe.

 

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.

 

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 $      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:

 

 

 

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.”

 

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 June 30, 2010.

 

We must generate approximately $        million of available cash to pay the minimum quarterly distribution for four quarters on all of the 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 pro forma available cash for the year ended December 31, 2009 would have been approximately $52.8 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 $      per unit per quarter (or $      per unit on an annualized basis) on all of the common units, subordinated units, and general partner units. Specifically, this amount would only have been sufficient to make a cash distribution of $      per unit per quarter (or $      per unit on an annualized basis) on all of the common and general partner units, or approximately     % of the minimum quarterly distribution, and a cash distribution of $      per unit per quarter (or $      per unit on an annualized basis) on all of the subordinated units, or approximately     % of the minimum quarterly distribution. If we had completed the transactions contemplated in this prospectus and the acquisition of all of our properties on July 1, 2009, our pro forma available cash for the twelve months ended June 30, 2010 would have been approximately $51.0 million. This amount would not have been sufficient to make a cash distribution for the twelve months ended June 30, 2010 at the minimum quarterly distribution of $      per unit per quarter (or $      per unit on an annualized basis) on all of the common units, subordinated units, and general partner units. Specifically, this amount would only have been sufficient to make a cash distribution of $      per unit per quarter (or $      per unit on an annualized basis) on all of the common and general partner units, or approximately     % of the minimum quarterly distribution, and a cash distribution of $      per unit per quarter (or $      per unit on an annualized basis) on all of the subordinated units, or approximately     % of the minimum quarterly distribution. 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 June 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 June 30, 2010.”

 

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,” 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 June 30, 2010, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

 

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 9% 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 $5.9 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 approximately $8.5 million to sustain the productive life of our assets. Based on our reserve report dated June 30, 2010, over the five-year period ending December 31, 2015, we expect that our annual capital expenditures will average approximately $14.4 million. 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:

 

 

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:

 

 

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:

 

 

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 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. 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, 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 derivative contracts. For example, some of the 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 derivatives 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 and 2014, approximately 19%, 27%, 32% and 34%, 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 derivative contracts. In addition, none of our pro forma estimated total NGL production is covered by derivative contracts at the closing of this offering. Likewise, we do not have or plan to have any 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.”

 

We expect to enter into derivative contracts covering approximately 65% to 85% of our estimated oil and natural gas production over a three- to-five year period on a rolling basis. 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 derivative contracts covering a specific portion of our production. The prices at which we enter into 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 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 derivative contracts, we might be forced to satisfy all or a portion of our 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 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 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:

 

 

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 $110.4 million, from $474.2 million to $363.8 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. 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 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 and June 30, 2010 included in this prospectus were prepared by our internal reserve engineers and professionals, but only our estimated proved reserves as of June 30, 2010 have been audited by Miller & Lents, Ltd., our independent petroleum engineering firm. Our internal estimates of proved reserves may differ materially from independent proved reserve estimates as a result of the estimation process employed by an independent reserve engineering firm. Our internal proved reserve estimates are based upon various assumptions, including assumptions required by the SEC related to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our internal proved reserve estimates may not be indicative of or may differ materially from the estimates of our proved reserves as of December 31, 2010 that will be prepared by Miller & Lents, Ltd.

 

Secondary and Tertiary Recovery Techniques May Not Be Successful, Which Could Adversely Affect Our Financial Condition or Results of Operations and, As a Result, Our Ability to Pay Distributions to Our Unitholders.

 

Approximately 55% of our pro forma production for the six months ended June 30, 2010 and 67% of our pro forma estimated proved reserves as of June 30, 2010 relied on secondary and tertiary recovery techniques, which include waterfloods and injecting gases into producing formations to enhance hydrocarbon recovery. If production response to these techniques is less than forecasted for a particular project, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing the capital to employ these techniques. Risks associated with secondary and tertiary recovery techniques include the following:

 

 

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:

 

 

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.

 

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.

 

A Portion of Our Assets Consists of Working Interests in Identified Producing Wells, Which Limits Our Ability to Drill Additional Wells to Increase Production or to Protect Our Reserves from Drainage.

 

At the closing of this offering, the Fund will contribute to us certain working interests in identified producing wells (often referred to as wellbore assignments) in its East Cowden Grayburg Unit in the Permian Basin operating area, which represent approximately 8% of our standardized measure and 7% of our estimated proved reserves as of June 30, 2010. Any mineral or leasehold interests or other rights that are assigned to us as part of each wellbore assignment will be limited to only that portion of such interests or rights that is necessary to produce hydrocarbons from that particular wellbore, and will not include the right to drill additional wells (other than replacement wells) within the area covered by the leasehold interest to which that wellbore relates. In addition, pursuant to the terms of the wellbore assignments from the Fund, our operation with respect to each wellbore will be limited to the interval from the surface to the deepest drilled depth of the wellbore, plus an additional 100 feet as a vertical easement for operating purposes only. The wellbore assignments also limit the horizontal reach of the assigned interest to any horizon accessible from the wellbore on the date of the assignments, including those horizons that are not currently producing within the vertical limit of the wellbore. We will not have the right to drill horizontally beyond the confines of the existing wellbore. As a result, in all of our operating areas, we do not own reserves in addition to those associated with a particular wellbore assignment, and therefore we will have no ability to drill, or participate in the drilling of, additional wells, including downspacing wells drilled by affiliates of the Fund and others. In addition, many of these wellbores are directly offset by potential drilling locations held by the Fund.

 

Furthermore, the owners of leasehold interests lying contiguous or adjacent to or adjoining our interests (including affiliates of the Fund) could take actions, such as drilling additional wells, that could adversely affect our operations. It is in the nature of petroleum reservoirs that when a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our estimated proved reserves. These restrictions on our ability to drill additional wells and to extend the vertical and horizontal limits of our existing wellbores and depletion of our estimated proved reserves from offset drilling locations could materially adversely affect our ability to maintain and grow our production and estimated reserves and to make cash distributions 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:

 

 

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:

 

 

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 estimated 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 June 30, 2010. Following 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 conjunction 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 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.” Our ability to comply with these restrictions and covenants in our credit facility in the future is uncertain and will be affected by the levels of cash flow

from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our credit facility that are not cured or waived within the appropriate time periods provided in our new credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

 

We anticipate that, like our predecessor’s credit facility, 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 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 derivative contracts. In the future, we may not be able to access adequate funding 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 lending counterparties 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 will 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 17% of our estimated proved reserves, as determined by value based on standardised 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:

 

 

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” and “— Other Regulation of the Oil and Natural Gas Industry” 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.”

 

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” 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” and “Business and Properties — Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.

 

The Recent Adoption of Derivatives Legislation By the 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.

 

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.

 

Following this offering, the Fund will control an aggregate of approximately     % 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 executive 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. Furthermore, certain directors and executive officers of our general partner are directors or executive officers of affiliates of our general partner, including Quantum Resources Management and Quantum Energy Partners. Conflicts of interest may arise 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. 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.” These potential conflicts include, among others, the following situations:

 

 

 

Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties.”

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.

 

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. Also pursuant to the omnibus agreement, the Fund must give us the 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. 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 provisions of the omnibus agreement will expire five years after the date the omnibus agreement is executed. 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 acquisition candidates. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

 

Neither We Nor Our General Partner Have Any Employees and We Rely Solely on the Employees of 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. 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.

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:

 

 

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 is an amount equal to the sum of (i) 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 (ii) 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 agreed upon by our general partner and 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.”

 

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 a time when it has received all or any portion of the quarterly management incentive fee for each of the immediately preceding four consecutive calendar quarters, to convert into Class B units up to 80% of the management incentive fee for a particular 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.”

 

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 Out Acquisitions and Business Opportunities and, Accordingly, May Have Conflicts of Interest in Allocating Time or Pursuing Business Opportunities.

 

To maintain and increase our levels of production, we will need to acquire oil and natural gas properties. Several of the officers and directors of our general partner, who are responsible for managing our operations and acquisition activities, hold similar positions with other entities that are in the 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 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” and “Conflicts of Interest and Fiduciary Duties.”

 

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.”

 

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 six months ended June 30, 2010, 3.5% of our unaudited pro forma Adjusted EBITDA, calculated prior to the payment of the fee, would have been approximately $1.3 million. 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.”

 

Unitholders Who Are Not Eligible Holders Will Not Be Entitled to Receive Distributions on, or Allocations of Income or Loss on, Their Common Units, and Their Common Units 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:

 

 

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 not receive distributions or allocations of income and loss on their common units and they run the risk of having their common units redeemed by us at the lower of their purchase price cost or 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” and “The Partnership Agreement — Non-Eligible Holders; Redemption.”

 

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 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     % of our outstanding common units held by the Fund 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. 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.”

 

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:

 

 

 

By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

 

Even If Unitholders Are Dissatisfied, They Cannot Remove Our General Partner Without Its Consent.

 

The 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. Following 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     % of our outstanding common units held by the Fund 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 executive officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and executive 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 securities of equal or senior rank will have the following effects:

 

 

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 held by the Fund 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 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 (ii) the current market price as of the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. At the completion of this offering, the Fund will control an aggregate of approximately     % of our outstanding common units held by the Fund and all of our subordinated units. For additional information about this call right, please read “The Partnership Agreement — Limited Call Right.”

 

If We Distribute Cash from Capital Surplus, Which is Analogous to a Return of Capital, Our Minimum Quarterly Distribution Will Be Reduced Proportionately, and the 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 securities. 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 and capital surplus, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions and the Management Incentive Fee.”