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TABLE OF CONTENTS

PART I

Item 1.	Business	9
Item 1A.	Risk Factors	28
Item 1B.	Unresolved Staff Comments	60
Item 2.	Properties	60
Item 3.	Legal Proceedings	60
Item 4.	Mine Safety Disclosures	60

PART II

Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases
	of Equity Securities	61
Item 6.	Selected Financial Data	67
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	71
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	92
Item 8.	Financial Statements and Supplementary Data	94
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	94
Item 9A.	Controls and Procedures	95
Item 9B.	Other Information	96

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	97
Item 11.	Executive Compensation	104
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
	Matters	115
Item 13.	Certain Relationships and Related Transactions, and Director Independence	118
Item 14.	Principal Accounting Fees and Services	122

PART IV

Item 15.	Exhibits, Financial Statement Schedules	123

Signatures		126

GLOSSARY OF OIL AND NATURAL GAS TERMS

API: American Petroleum Institute is the main U.S. trade association for the oil and natural gas industry whose functions include establishment and certification of industry standards like the gravity (density) of petroleum.

Basin: A low area in the Earth’s crust in which sediments have accumulated.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bbl/d: One Bbl per day.

Bcf: One billion cubic feet of natural gas.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

Boe/d: One Boe per day.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Completion: The installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to report to the appropriate authority the well has been abandoned.

Condensate: A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.

Developed oil and natural gas reserves: Reserves of any category that can be expected to be recovered:

·	through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and

·	through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development costs: Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining water, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves;

·	drill and equip development wells, development-type stratigraphic test wells and service wells, including the costs of platforms and well equipment such as casing, tubing, pumping equipment and the wellhead assembly;

·	acquire, construct and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

·	provide improved recovery systems.

Development Project: The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Hole or Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically producible: A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Enhanced Recovery: Any method used to drive oil from reservoirs into a well in excess of that which could be produced through natural reservoir pressure, energy, or drive.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

FASB: Financial Accounting Standards Board

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have a working interest.

LLS: Louisiana Light Sweet

MBbls: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

Mcf: One thousand cubic feet of natural gas.

MMBbls: One million barrels of oil or other liquid hydrocarbons.

MMBoe: One million Boe.

MMBtu: One million British thermal units.

MMcf: One thousand Mcf.

Net acres or net wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.

Net production: Production that is owned by us less royalties and production due others.

Net revenue interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs: The combination of ethane, propane, butane and natural gasolines which, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.

Novate: To substitute by mutual agreement one obligation for another, such as the substitution of one party to a contract for another, with the intent to extinguish the old obligation. For example the substitution of one party to a derivative contract for another party upon mutual consent of the original counterparties and the concurrence of the new party.

NYMEX: New York Mercantile Exchange

Oil: Oil and condensate.

Productive well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved developed reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Proved reserves: Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. This definition has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Proved undeveloped reserves: Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. This definition has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Realized price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.

Reserves: Estimated remaining quantities of mineral deposits anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

SEC: The U.S. Securities and Exchange Commission

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Standardized measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the unweighted arithmetic average first-day of-the-month prices for the prior 12 months), less future development, production and income tax expenses and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore: The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

Working interest: The operating interest that gives the owner the right to drill, produce and conduct operating activities on a property and a share of its production.

Workover: Operations on a producing well to restore or increase production.

WTI: West Texas Intermediate

NAMES OF ENTITIES

As used in this Form 10-K, unless we indicate otherwise:

·	“QR Energy,” “the Partnership,” “we,” “us” or “our” or like terms refer collectively to QR Energy, LP and its subsidiaries;

·	our “general partner” or “QRE GP” refers to QRE GP, LLC, the general partner of the Partnership;

·	the “Fund,” or “Fund Entities” refer collectively to, or in any combination of Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC; or referred to individually as a “Fund Entity;”

·	the “Predecessor” refers to QA Holdings, LP, our predecessor for accounting purposes and the indirect owner of the general partner interests of the Fund Entities;

·	“QA Global” refers to QA Global GP, LLC, the general partner of QA Holdings, LP and the Fund Entities above;

·	“Quantum Energy Partners” refers collectively to Quantum Energy Partners, LLC, its affiliated private equity funds and their respective portfolio investments;

·	“Quantum Resources Management” or “QRM” 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;

·	“OLLC” refers to QRE Operating, LLC, our wholly owned subsidiary through which we operate our properties;

·	“QRE FC” refers to QRE Finance Corporation, LLC, our wholly owned subsidiary formed for the sole purpose of serving as a co-issuer of our debt securities;

·	“Denbury Acquisition” refers to the Fund’s acquisition of approximately $893.0 million of oil and natural gas properties, which we refer to as the “Denbury Assets,” from Denbury Resources Inc. in May 2010;

·	“Melrose Acquisition” refers to the Fund’s acquisition of approximately $62.3 million of oil and natural gas properties, which we refer to as the “Melrose Properties” from Melrose Energy Company in December 2010;

·	“October 2011 Transferred Properties” refers to the net assets we received as a result of our acquisition of approximately $578.8 million of oil and natural gas properties from the Fund in October 2011 accounted for as a transaction between entities under common control; and

·	“December 2012 Transferred Properties” refers to the net assets we received as a result of our acquisition of approximately $143.6 million of oil and natural gas properties from the Fund in December 2012 accounted for as a transaction between entities under common control.

FORWARD–LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

·	business strategies;

·	ability to replace the reserves we produce through drilling and property acquisitions;

·	drilling locations;

·	oil, natural gas and natural gas liquids (NGLs) reserves;

·	technology;

·	realized oil and natural gas prices;

·	production volumes;

·	lease operating expenses;

·	general and administrative expenses;

·	future operating results; and

·	plans, objectives, expectations and intentions.

These types of statements, other than statements of historical fact included in this Form 10-K, are forward-looking statements. These forward-looking statements may be found in “Item 1. Business,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other sections of this Form 10-K. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations as expressed in this Form 10-K including, but not limited to:

·	our ability to generate sufficient cash to pay the minimum quarterly distribution on our common units;

·	our substantial future capital requirements, which may be subject to limited availability of financing;

·	uncertainty inherent in estimating our reserves;

·	our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base;

·	cash flows and liquidity;

·	potential shortages of drilling and production equipment;

·	potential difficulties in the marketing of, and volatility in the prices for, oil, natural gas and NGLs;

·	uncertainties surrounding the success of our secondary and tertiary recovery efforts;

·	competition in the oil and natural gas industry;

·	general economic conditions, globally and in the jurisdictions in which we operate;

·	legislation and governmental regulations, including climate change legislation and federal or state regulation of hydraulic fracturing;

·	the risk that our hedging strategy may be ineffective or may reduce our income;

·	actions of third-party co-owners of interest in properties in which we also own an interest; and

·	risks related to potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties.

The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in “Item 1A. Risk Factors” and elsewhere in this Form 10-K. All forward-looking statements speak only as of the date of this report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

PART I

ITEM 1. BUSINESS

Overview

QR Energy, LP is a Delaware limited partnership formed in September 2010 by affiliates of the Fund to own and exploit producing oil and natural gas properties.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties, and our business activities are conducted through OLLC, our wholly owned subsidiary. Our properties are located in Alabama, Arkansas, Florida, Kansas, Louisiana, Michigan, New Mexico, Oklahoma and Texas.

Our properties consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, predictable production profiles. As of December 31, 2012, our total estimated proved reserves were approximately 99.1 MMBoe, of which approximately 68% were oil and NGLs and 75% were classified as proved developed reserves. As of December 31, 2012, our estimated proved reserves had a standardized measure of $1.6 billion. As of December 31, 2012, we produced from 4,527 gross (2,195 net) wells across our properties, with an average working interest of 49%.

Oil and natural gas reserve information included in this Form 10-K is derived from our reserve report prepared by Miller and Lents, Ltd., our independent reserve engineers. The following table summarizes information about our proved oil and natural gas reserves by geographic region as of December 31, 2012 and our average net production for the year ended December 31, 2012:


	Estimated Net Proved Reserves						Production
	Oil &		Natural			Standardized ⁽¹⁾	Average Net Production ⁽²⁾
	Cond.	NGLs	Gas			Measure		% of	%	Producing Wells
	(MBbls)	(MBbls)	(MMcf)	MBoe		($ millions)	Boe/d	Total	Liquids	Gross	Net
Permian Basin	24,906.5	3,659.2	37,274.0	34,778.0	$	640.9	6,539	39	70	2,816	987
Ark-La-Tex	20,508.9	5,532.4	134,452.0	48,450.0		592.6	5,260	32	37	1,255	955
Gulf Coast	8,811.7	1,127.1	2,276.7	10,318.3		287.4	3,316	20	97	64	50
Mid-Continent	2,297.2	233.3	15,993.2	5,196.0		78.2	1,473	9	47	376	187
Michigan	313.8	-	324.5	367.9		7.7	65	-	100	16	16
Total	56,838.1	10,552.0	190,320.4	99,110.2	$	1,606.8	16,653	100	63	4,527	2,195

⁽¹⁾	As of December 31, 2012 our standardized measure was $1.6 billion. Because we are a limited partnership, we are generally not subject to federal or state income tax and thus make no provision for federal or state income taxes in the calculation of our standardized measure.

⁽²⁾	Production data includes all 2012 volumes and wells attributable to the December 2012 Transferred Properties d as if the Partnership owned such assets as of the beginning of the year.

Recent Developments

On December 28, 2012, the Fund sold the December 2012 Transferred Properties, located in the Florida panhandle, to the Partnership in exchange for approximately $28.6 million in cash, after customary purchase price adjustments, and the assumption of $115 million in debt (the “December 2012 Transaction”). The December 2012 Transaction was accounted for as a transaction between entities under common control whereby the December 2012 Transferred Properties were recorded at historical book value.

On December 12, 2012, we issued 12,000,000 common units representing limited partnership interests in us to the public (the “December 2012 Equity Offering”). In conjunction with the December 2012 Equity Offering, the Partnership granted the underwriters an option for 30 days to purchase up to an additional 1,800,000 common units from the Partnership, which was exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us at a public offering price of $16.24 per unit. Proceeds from the December 2012 Equity Offering, net of transaction costs of $0.2 million and underwriters’ discount of $9.0 million, were approximately $214.9 million and were used to repay an equivalent amount of borrowings under our revolving credit facility.

On December 4, 2012, we closed the acquisition of mature, predominantly oil properties (“the East Texas Oil Field Properties”) from an undisclosed private seller located in an East Texas field for $214.3 million in cash subject to customary purchase price adjustments (the “East Texas Oil Field Acquisition”). The acquired properties had estimated proved reserves of 10.8 MMBoe as of December 31, 2011 utilizing SEC case pricing. The acquisition had an effective date of November 1, 2012. See Part II, Item 8. Financial Statements and Supplementary Data – Note 4 – Acquisitions for further details. –

On September 7, 2012, we filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes issued on July 30, 2012 to exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012. The exchange offer was completed on November 7, 2012.

On July 30, 2012, we and our wholly-owned subsidiary QRE FC, issued $300 million of 9.25% Senior Notes (the “Senior Notes”) due 2020. See Part II, Item 8. Financial Statements and Supplementary Data – Note 8 – Long-Term Debt for further details. We subsequently filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes to exchange the Senior Notes for registered notes with substantially identical terms as the Senior Notes. The exchange offer was completed on November 7, 2012.

On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register, among other securities, our debt securities, which were co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. See Part II, Item 8. Financial Statements and Supplementary Data – Note 18 – Subsidiary Guarantors for further details.

On April 20, 2012, we closed the acquisition of primarily oil properties from Prize Petroleum, LLC and Prize Petroleum Pipeline, LLC (collectively “Prize”) for $225.1 million in cash after customary purchase price adjustments (the “Prize Acquisition”). The acquired properties were predominantly low decline, long life oil properties, most of which are located in the Ark-La-Tex area, and had estimated proved reserves as of December 31, 2011 utilizing SEC prices of 13.3 MMBoe. The acquisition had an effective date of January 1, 2012. See Part II, Item 8. Financial Statements and Supplementary Data – Note 4 – Acquisitions for further details.

On April 17, 2012, we issued 6,202,263 common units representing limited partnership interests in us, and the Fund sold 11,297,737 of its common units it held in us (the “April 2012 Equity Offering”), to the public pursuant to a registration statement filed with the Securities and Exchange Commission (the “SEC”). In conjunction with the April 2012 Equity Offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. Refer to Part II, Item 8. Financial Statements and Supplementary Data – Note 10 – Partners’ Capital for further details. Proceeds from the April 2012 Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.

In conjunction with the acquisitions discussed above, we have increased our credit facility capacity to $1.5 billion and extended the maturity to April 2017. Effective January 15, 2013, our borrowing base increased to $900 million with $406.5 million of availability.

Presentation

Because the October 2011 Transferred Properties and the December 2012 Transferred Properties were acquired from the Predecessor or its affiliates, the acquisitions were accounted for as transactions between entities under common control, whereby the Partnership’s accompanying consolidated financial statements included in Part II, Item 8. Financial Statements and Supplementary Data have been revised for the period from December 22, 2010 to December 31, 2010 and the years ended December 31, 2011 and 2012, similar to a pooling of interests, to include the financial position, results of operations, and cash flows of the net assets attributable to the October 2011 Transferred Properties and the December 2012 Transferred Properties. See Part II, Item 8. Financial Statements and Supplementary Data – Note 2 – Significant Accounting Policies for more information on the Partnership’s accounting presentation.

Business Strategy

Our primary business objective is to generate predictable cash flows which will allow us to make quarterly cash distributions to our unitholders and, over time, to increase our quarterly cash distributions. To achieve our objective, we intend to execute the following business strategies:

·	Pursue accretive acquisitions of long-lived, low-risk producing oil and natural gas properties throughout North America;

·	Strategically utilize our relationship with the Fund to gain access to, and from time to time, acquire its producing oil and natural gas properties that meet our acquisition criteria;

·	Leverage our relationship with the Fund and Quantum Energy Partners to participate in acquisitions of third-party legacy assets and to increase the size and scope of our potential third-party acquisition targets;

·	Reduce costs and maximize recovery to drive value creation in our producing properties;

·	Mitigate commodity price risk and maximize cash flow visibility through a disciplined commodity hedging strategy; and

·	Maintain a balanced capital structure to provide financial flexibility for acquisitions.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our objective of generating and growing cash available for distribution:

·	Our diversified asset portfolio is characterized by relatively low geologic risk, well-established production histories and low production decline rates;

·	Our relationship with the Fund, which provides us with access to a portfolio of additional mature producing oil and natural gas properties that meet our acquisition criteria;

·	Our relationship with QRM, 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; and

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

Our Relationship with the Fund

The Fund is a collection of limited partnerships formed by two of the co-founders of Quantum Energy Partners and Don Wolf, the Chairman of the Board of our general partner, for the purpose of acquiring mature, legacy producing oil and natural gas properties with long-lived production profiles. The Fund is managed by Quantum Resources Management, a full service management company formed to manage the oil and natural gas interests of the Fund. Our general partner has entered into a services agreement with Quantum Resources Management in which Quantum Resources Management has agreed to provide the administrative and acquisition advisory services that we believe are necessary to allow our general partner to manage, operate and grow our business.

The Fund is contractually committed to providing us with opportunities to purchase additional proved reserves in future periods under specified circumstances. Under the terms of our omnibus agreement, the Fund has committed to offer us the first opportunity to purchase properties that it may offer for sale, so long as the properties consist of at least 70% proved developed producing reserves, as measured by value.

The Fund will determine whether any group of properties offered for sale meets the 70% threshold, and therefore, whether it is obligated to offer such properties to us. The 70% threshold is a value-weighted determination made by the Fund, acting in good faith pursuant to the terms of our omnibus agreement, and is subject to a number of subjective assumptions. As such, other than the Fund’s obligation to act in good faith, there are no additional safeguards in place to prevent the Fund from selecting a subset of assets that do not meet this standard or allocating value in a manner where the proved developed producing assets are below the 70% threshold. Given the Fund’s significant ownership in us, we believe there is a sufficient economic incentive to deter the Fund from structuring its asset dispositions in an attempt to circumvent our contractual rights under the omnibus agreement.

We believe the Fund has a vested interest in our ability to increase our reserves and production since it holds an aggregate 29.3% limited partner interest in us including all of our preferred units as of March 5, 2013. Except as provided in the omnibus agreement, as described above, the Fund has no obligation to offer additional properties to us. If the Fund fails to present us with, or successfully competes against us for acquisition opportunities, then we may not be able to replace or increase our estimated proved reserves, which would adversely affect our cash flow from operations and our ability to make cash distributions to our unitholders.

Quantum Energy Partners

Quantum Energy Partners is a private equity firm that was founded in 1998 to make investments in the energy sector. Two of the co-founders and certain other employees of Quantum Energy Partners own interests in the general partner of the Fund. Two of the co-founders also own interests in our general partner. The employees of Quantum Energy Partners are experienced energy professionals with expertise in finance and operations and broad technical skills in the oil and natural gas business. In connection with the business of Quantum Energy Partners, these employees review a large number of potential acquisitions and are involved in decisions relating to the acquisition and disposition of oil and natural gas assets by the various portfolio companies in which Quantum Energy Partners owns interests. Although there is no obligation to do so, to the extent not inconsistent with their fiduciary duties and obligations to the investors and other parties involved with Quantum Energy Partners, Quantum Energy Partners may refer to us or allow us to participate in new acquisitions by its portfolio companies and may cause its portfolio companies to sell oil and natural gas assets to us in transactions that would be beneficial to all parties. Given this potential alignment of interests and the overlapping ownership of the management and general partners of Quantum Energy Partners, the Fund and us, we believe we will benefit from the collective expertise of the employees of Quantum Energy Partners, their extensive network of industry relationships and the access to potential acquisition opportunities that would not otherwise be available to us.

Our Areas of Operation

We operate our business in certain fields in the Permian Basin, Ark-La-Tex, Mid-Continent, Gulf Coast and Michigan areas. We continue to grow our oil and natural gas assets with strategic acquisitions from third parties and from acquisitions from the Fund. The table below summarizes our average net production, average sales prices by product and average production costs for the years ended December 31, 2012 and 2011 and our reserves as of December 31, 2012 and 2011 for each of our areas:


2012 ⁽¹⁾	Permian Basin			Ark-La-Tex			Gulf Coast			Mid-Continent			Michigan ⁽²⁾			Total
Production:
Oil (MBbl)		1,341			459			1,055			227			24			3,106
Natural Gas (Mmcf)		4,305			7,247			211			1,712			-			13,475
NGL (MBbl)		333			259			124			27			-			743
Mboe		2,393			1,925			1,214			539			24			6,095
Boe/d		6,539			5,260			3,316			1,473			65			16,653

Average sales price per unit:
Oil (per Bbl)	$	88.01		$	93.93		$	107.11		$	91.13		$	77.67		$	95.52
Natural gas (per Mcf)	$	3.01		$	2.73		$	3.09		$	2.19		$	-		$	2.76
Natural gas liquids (per Bbl)	$	38.90		$	45.93		$	67.27		$	42.11		$	-		$	46.21

Lease operating expense (per Boe):	$	18.23		$	12.67		$	29.93		$	16.94		$	31.04		$	18.74

Reserves:
MBoe		34,778.0			48,450.0			10,318.3			5,196.0			367.9			99,110.2
Liquids		82	%		54	%		96	%		49	%		85	%		68	%
Proved Developed		67	%		74	%		100	%		90	%		100	%		75	%
Proved Operated		74	%		99	%		94	%		72	%		100	%		88	%
Total Proved		35	%		49	%		10	%		5	%		1	%		100	%

2012 Actual Capital Expenditures	$	72,236		$	15,003		$	31,089		$	5,543		$	-		$	123,871
2013 Expected Capital Budget:	$	42,600		$	25,800		$	17,900		$	3,800		$	-		$	90,100


2011 ⁽¹⁾	Permian Basin			Ark-La-Tex			Gulf Coast			Mid-Continent			Total
Production:
Oil (MBbl)		1,220			185			951			238			2,594
Natural Gas (Mmcf)		5,188			7,886			309			1,723			15,106
NGL (MBbl)		370			158			126			26			680
Mboe		2,455			1,657			1,129			551			5,792
Boe/d		6,726			4,540			3,093			1,509			15,868

Average sales price per unit:
Oil (per Bbl)	$	90.74		$	93.48		$	108.20		$	91.78		$	97.43
Natural gas (per Mcf)	$	4.58		$	4.02		$	4.39		$	5.15		$	4.35
Natural gas liquids (per Bbl)	$	50.81		$	54.19		$	74.99		$	49.04		$	56.02

Lease operating expense (per Boe):	$	16.20		$	9.79		$	35.03		$	16.61		$	18.07

Reserves:
MBoe		37,390.9			29,078.2			8,130.1			6,721.0			81,320.2
Liquids		81	%		26	%		89	%		48	%		59	%
Proved Developed		66	%		62	%		97	%		99	%		70	%
Proved Operated		73	%		99	%		87	%		78	%		84	%
Total Proved		46	%		36	%		10	%		8	%		100	%

⁽¹⁾	The Partnership’s operating results for the years ended December 31, 2012 and 2011 have been revised to include the results attributable to the December 2012 Transferred Properties as if the Partnership owned the properties during these periods.

⁽²⁾	Acquired through the 2012 Prize Acquisition.

Our 2010 operating results for average net production, average sales price by product and average production costs are not presented, as we had only 10 days of operations from December 22, 2010 to December 31, 2010, and they are not comparable with our current results.

Permian Basin

The Permian Basin area includes properties located in west Texas and southeast New Mexico and produces from a variety of reservoirs such as the San Andres, Grayburg and Clearfork formations at depths ranging from 4,000 to 11,000 feet. Many of these properties are under secondary recovery waterflood operations. During 2012, we invested $72.2 million in capital in the Permian Basin, primarily on waterflood developments in our Fuhrman Mascho and Turner Gregory fields. Of the 46 net wells we drilled in the Permian Basin in 2012, 40 wells were in these two fields. The remaining wells drilled in 2012 were in our operated Blineberry-Drinkard and GPM fields, and in our non-operated Westbrook, Wasson, and Adair properties.

During 2013, we expect to invest approximately $42.6 million in capital in the Permian Basin, primarily on further expanding our waterflood operations, recompletions, workovers, facility upgrades, infill drilling and well and facility work.

Ark-La-Tex

The Ark-La-Tex area includes properties located in east Texas, northern Louisiana and southern Arkansas. These properties produce from formations such as the Cotton Valley Sand, Haynesville Sand, Woodbine Sand and Smackover Carbonate at depths ranging from 1,000 to 11,000 feet. During 2012, we acquired interests in the East Texas Oil Field and Neches fields in Texas and the Homer Field in Louisiana. In 2012, we invested $15.0 million in capital in this area, primarily on recompletions, returning wells to production, artificial lift enhancements and facility upgrades in the White Oak/Glenwood, Neches, Shongaloo/Walker Creek, Overton, and Dorcheat Macedonia fields. We participated in drilling one gross well in this area in a field in which we had a small (<10%) working interest.

During 2013, we expect our Ark-La-Tex capital budget to be approximately $25.8 million, primarily for infill drilling, well work, recompletions, well reactivations, artificial lift enhancements, workovers and facility upgrades.

Gulf Coast

The Gulf Coast area includes properties located in southern Alabama, southeast Texas and Florida. We acquired the Fund’s properties in the Jay Field located in the Florida panhandle in connection with the December 2012 Transferred Properties. These properties produce from formations such as the Yegua Sand and Smackover Carbonate at depths ranging from 8,000 to 15,000 feet. During 2012, we invested $31.1 million in this area, primarily on well work and facility upgrades at the Jay Field, though some capital was also invested in a workover at the Clinton field and in facility work at the non-operated Big Escambia Creek plant.

During 2013, we expect our Gulf Coast capital budget to be approximately $17.9 million, primarily for well work, workovers, and plant and facility upgrades.

Mid-Continent

The Mid-Continent area includes properties located in Oklahoma, southwestern Kansas and the Texas panhandle. These properties produce from formations such as the Cottage Grove Sand, Atoka, Redfork and Lansing at depths ranging from 3,000 to 15,000 feet. During 2012, we invested $5.5 million in capital in this area, primarily on well work and facility upgrades at our Apache, Harmon East, Adams Ranch, Moorehead Northeast, Custer City North, Mills Ranch, Calumet and Oakdale fields. We also participated in drilling two gross wells in which we had small (< 20% interests).

During 2013, we expect our Mid-Continent capital budget to be approximately $3.8 million, primarily for drilling, well work, artificial lift enhancements, workovers and facility upgrades.

Michigan

We acquired the Rich Field in Michigan as part of the Prize Acquisition in 2012. During 2013, we plan to evaluate further development options in this area.

Our Oil and Natural Gas Data

Our Reserves

Internal Controls. Our proved reserves, which are estimated at the well or unit level, are compiled for reporting purposes by Quantum Resources Management’s corporate reservoir engineering staff, all of whom are independent of Quantum Resources Management operating teams. Quantum Resources Management maintains internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interacts with Quantum Resources Management’s internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by our senior management on a semi-annual basis. Our reserve estimates are prepared by our independent third-party reserve engineers, Miller & Lents, Ltd., at least annually.

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

Qualifications of Responsible Technical Persons

Internal Quantum Resources Management Person. Our Senior Reservoir Engineer is the technical person primarily responsible for overseeing the preparation of our reserves estimates and is also responsible for liaison with and oversight of our third-party reserve engineer. The Senior Reservoir Engineer has more than 20 years of industry experience with positions of increasing responsibility in reservoir engineering and reserves evaluation with Amoco, Fletcher Challenge Petroleum, Ocean Energy, Devon, Anadarko, and BreitBurn Energy. The Senior Reservoir Engineer holds a Bachelor of Science in Chemical Engineering.

Miller & Lents. Miller & Lents, Ltd. is an independent oil and natural gas consulting firm. No director, officer, or key employee of Miller & Lents, Ltd. has any financial ownership in us, Quantum Resources Management, the Fund or any of their respective affiliates. Miller & Lents, Ltd.’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and Miller & Lents, Ltd. has not performed other work for Quantum Resources Management, the Fund or us that would affect its objectivity. The preparation of the Miller & Lents, Ltd. reserve report was overseen by the firm’s Vice President who is an experienced reservoir engineer having been a practicing petroleum engineer since June of 1981. He has more than 20 years of experience in reserves evaluation. He holds a Bachelors of Science Degree in Chemical Engineering and is a registered professional engineer in Texas.

Estimated Proved Reserves. The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2012 based on reserve reports prepared by Miller & Lents, Ltd. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.


	Oil &		Natural			Standardized
	Cond.	NGLs	Gas	Total		Measure
	(MBbls)	(MBbls)	(MMcf)	MBoe		($ thousands)
Permian Basin:
Developed	14,173.0	3,125.5	35,023.8	23,135.8	$	462,357
Undeveloped	10,733.5	533.7	2,250.2	11,642.2	$	178,567
Total	24,906.5	3,659.2	37,274.0	34,778.0	$	640,924

Ark-La-Tex
Developed	19,243.4	3,697.1	78,734.3	36,062.9	$	574,804
Undeveloped	1,265.5	1,835.3	55,717.7	12,387.1	$	17,781
Total	20,508.9	5,532.4	134,452.0	48,450.0	$	592,585

Gulf Coast
Developed	8,811.7	1,127.1	2,276.7	10,318.3	$	287,443
Undeveloped	-	-	-	-	$	-
Total	8,811.7	1,127.1	2,276.7	10,318.3	$	287,443

Mid-Continent
Developed	1,945.1	174.8	15,341.0	4,676.7	$	68,433
Undeveloped	352.1	58.5	652.2	519.3	$	9,805
Total	2,297.2	233.3	15,993.2	5,196.0	$	78,238

Michigan
Developed	313.8	-	324.5	367.9	$	7,652
Undeveloped	-	-	-	-	$	-
Total	313.8	-	324.5	367.9	$	7,652

Total
Developed	44,487.0	8,124.5	131,700.3	74,561.6	$	1,400,689
Undeveloped	12,351.1	2,427.5	58,620.1	24,548.6	$	206,153
Total	56,838.1	10,552.0	190,320.4	99,110.2	$	1,606,842

The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal and external reserve estimates, see Part I, Item 1A. Risk Factors – Risks Related to Our Business. Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

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

Production, Revenue and Price History

For a description of the Partnership’s and the Predecessor’s historical production, revenues and average sales prices and unit costs, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

Development of Proved Undeveloped Reserves

Recovery of proved undeveloped (PUD) reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but future events, including commodity price changes, may cause these assumptions to change. In addition, estimates of PUD reserves and proved developed non-producing reserves are inherently subject to greater uncertainties than estimates of proved developed producing reserves. For further discussion of our reserves, see Part II, Item 8. Financial Statements and Supplementary Data - Supplemental Oil and Natural Gas Information.

We currently have 376 undeveloped locations. All of our PUD locations are adjacent to existing productive wells. Therefore, the reservoir risk is lower than PUDs associated with step out or field extensions.

We assess our PUD reserves on a semiannual basis. At December 31, 2012, we had 24,549 MBoe of consolidated PUD reserves, an increase of 640 MBoe of PUD reserves compared to December 31, 2011 as revised based on our acquisition of the December 2012 Transferred Properties as the transaction was between entities under common control. During 2012, we added 2,342 MBoe of PUD reserves, primarily due to our drilling and optimization activities.

We spent approximately $40.5 million, during 2012 to convert approximately 5% or 1,238 MBoe of our prior year-end PUD reserves to proved developed reserves. In our December 31, 2012 reserve report, the amounts estimated to be spent over the next five years to develop our consolidated PUD reserves are $324.2 million or an average of $64.8 million per year. The amounts estimated to be spent to develop our PUD reserves are a result of our capital focus to develop our core projects. The amounts and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and commodity prices.

All of the 24,549 MBoe of PUD reserves at December 31, 2012, and since their initial recording, are inside of our current five-year development plan.

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2012.


	Oil		Natural Gas
	Gross	Net	Gross	Net
Operated	1,622	1,545	697	501
Non-operated	1,905	65	303	84
Total	3,527	1,610	1,000	585

Developed Acreage

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on our properties range from less than 1% to 66%, resulting in a net revenue interest to us ranging from 34% to 100%, or 82.4% on average. As of December 31, 2012, all of our leases are held by production except 2,760 gross and net acres.

The following table sets forth information as of December 31, 2012 relating to our leasehold acreage. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.


	Developed Acreage
	Gross	Net
Permian Basin	83,100	57,954
Ark-La-Tex	94,715	61,500
Gulf Coast	16,990	14,894
Mid-Continent	115,595	59,231
Michigan	2,840	2,840
Total	313,240	196,419

Title to Properties

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

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

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Form 10-K.

Drilling Activities

Our drilling activities consist entirely of development wells. The following table sets forth information with respect to wells drilled and completed by us and our Predecessor during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. As of December 31, 2012, we had no drilling activities currently in progress.


	Year Ended December 31,

	Partnership				Predecessor
	2012		2011		2010 ⁽¹⁾
	Gross	Net	Gross	Net	Gross	Net
Productive	93	47	88	11	72	4
Dry	-	-	-	-	-	-
Total	93	47	88	11	72	4

⁽¹⁾	During 2010, we have made no allocation of drilling activity for the 10-day period from December 22, 2010 through December 31, 2010 between us and the Predecessor, as the allocable drilling activity for this period is inconsequential.

Operations

General

We operated approximately 90% of our assets as determined by value, based on standardized measure as of December 31, 2012. We design and manage the development, recompletion or workovers for all of the wells we operate including the supervision of operation and maintenance activities. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on the properties we operate. Independent contractors provide all the equipment and personnel associated with these activities. Pursuant to our general partner’s services agreement, Quantum Resources Management provides certain administrative services to us. Quantum Resources Management employs production and reservoir engineers, geologists and other specialists, as well as field personnel that may perform work on our behalf. See Part III Item 13. Certain Relationships and Related Transactions, and Director Independence ‒ Services Agreement. We charge the nonoperating partners a contractual administrative overhead charge for operating the wells. Some of our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies.

Administrative Services Fee

Our general partner has entered into a services agreement with Quantum Resources Management, pursuant to which Quantum Resources Management was 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, through December 31, 2012. These fees are included in general and administrative expenses in our consolidated statement of operations.

Beginning on January 1, 2013, QRM is entitled to a quarterly reimbursement of general and administrative charges based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. The fee will include direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If the Fund or its affiliates raise a second fund, the quarterly administrative services costs will be further divided to include an allocation to the second fund as well. QRM will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.

For a detailed description of the administrative services fee paid Quantum Resources Management pursuant to the services agreement, see Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence ‒ Services Agreement.

Marketing, Major Customers and Delivery Commitments

The following table indicates our significant customers which accounted for 10% or more of our total revenues for the periods indicated:



	Partnership						Predecessor
	December 31, 2012 ⁽¹⁾		December 31, 2011 ⁽¹⁾		December 22, 2010 to December 31, 2010 ⁽¹⁾		January 1, 2010 to December 21, 2010
ConocoPhillips	12	%	11	%	(2)		(2)
Plains Marketing LP	13	%	(2)		(2)		(2)
Shell Trading US Company	33	%	29	%	23	%	45	%
Sunoco Inc (U.S.)	(2)		(2)		(2)		10	%
ExxonMobil Corporation	(2)		12	%	34	%	(2)

⁽¹⁾	In 2012, 2011 and 2010 these percentages are reflective as if the Partnership owned all of the December 2012 Transferred Properties for the entire year.

⁽²⁾	These customers accounted for less than 10% of total revenues for the periods indicated.

ConocoPhillips, Plains Marketing LP and ExxonMobil Corporation purchase oil production pursuant to existing marketing agreements with terms that are currently on “evergreen” status and renew on a month-to-month basis until either party gives 30-day advance written notice of non-renewal.

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

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

Derivatives Activities

We enter into commodity derivative contracts with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. Our current commodity derivative contracts include fixed price swaps and collars on future oil production at WTI and LLS prices, fixed price swaps and basis swaps on future natural gas production with NYMEX prices, natural gas puts, collars on future natural gas production with Henry Hub prices and floors on future natural gas production with Henry Hub prices.

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those in our credit facility) to fixed interest rates. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We will continue to evaluate the benefit of employing derivatives in the future. See Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.

Competition

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

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, resulting in seasonal fluctuations in the price we receive for our natural gas production. Seasonal anomalies such as mild winters or cooler summers sometimes lessen this fluctuation. Seasonal weather changes may also affect our operations. Tropical storms and hurricanes in the Gulf Coast area may cause us to temporarily shut—in production. Also periodic storms in the winter may impede our operations.

Environmental and Occupational Safety and Health Matters

General

Our oil and natural gas production operations are subject to stringent and complex federal, regional, state and local laws and regulations governing occupational safety and health, the discharge of materials into the environment and environmental protection. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of orders enjoining performance of some or all of our operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well construction, drilling, water management or completion activities, waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results.

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

Hazardous Substances and Wastes

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

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

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

Water Discharges

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure, or SPCC, plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit.

The Oil Pollution Act of 1990, as amended, or OPA, amends the Clean Water Act, sets minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.

Hydraulic Fracturing

Hydraulic fracturing is an important and common industry practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. In addition, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states, including Louisiana and Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Nevertheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our hydraulic fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our pollution liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Air Emissions

The federal Clean Air Act, or CAA, as amended, and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, on August 16, 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. With regard to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2013. We are currently reviewing this new rule and assessing its potential impacts on our operations. Compliance with these requirements could increase our costs of development and production, which could be significant.

Climate Change

Based on findings made by the EPA in December 2009 that emissions of carbon dioxide, or CO2, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA adopted regulations under existing provisions of the CAA that establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which include the majority of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit 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.

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

Activities on Federal Lands

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

Endangered Species Act Considerations

Environmental laws such as the Endangered Species Act, as amended, or ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States, and prohibits taking of endangered species. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

OSHA

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

Other Regulation of the Oil and Natural Gas Industry

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

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

Drilling and Production

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

·	the location of wells;

·	the method of drilling and casing wells;

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

·	the plugging and abandoning of wells; and

·	notice to surface owners and other third parties.

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

Natural Gas Regulation

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

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

State Regulation

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

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

Employees

The officers of our general partner manage our operations and activities. However, neither we, our subsidiaries, nor our general partner have employees. Our general partner has entered into a services agreement with Quantum Resources Management pursuant to which Quantum Resources Management performs services for us, including the operation of our properties. See Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence for further details.

As of December 31, 2012, Quantum Resources Management had 293 employees, including 15 engineers, 6 geologists and 15 land professionals. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that Quantum Resources Management’s relations with its employees are satisfactory. We will also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, finance and other disciplines as needed.

Offices

Our principal executive office is located at 1401 McKinney Street, Suite 2400, Houston, Texas 77010. Our main telephone number is (713) 452-2200.

Available Information

Our annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our website at www.qrenergylp.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. These documents are also available on the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. Our website also includes our Code of Business Conduct, our Corporate Governance Guidelines, our Financial Code of Ethics and the charters of our audit committee, conflicts committee and compensation committee. No information from either the SEC’s website or our website is incorporated herein by reference.

ITEM 1A. RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. 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 may not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment. Other risks are also described in “Item 1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Risks Related to Our Business

We may not have sufficient cash to pay distributions 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 distributions to our common units.

Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. We intend to reserve a portion of our cash generated from operations to develop our oil and natural gas properties and to acquire additional oil and natural gas properties to maintain and grow our oil and natural gas reserves.

The amount of cash we actually generate will depend upon numerous factors related to our business that may be beyond our control, including, among other things, the risks described in this section.

In addition, the actual amount of cash that we will have available for distribution to our unitholders will depend on other factors, including:

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

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

·	the effectiveness of our commodity price hedging strategy;

·	the cost to produce our oil and natural gas assets;

·	the level of our capital expenditures, including scheduled and unexpected maintenance expenditures;

·	the cost of acquisitions;

·	our ability to borrow funds under our credit facility;

·	prevailing economic conditions;

·	sources of cash used to fund acquisitions;

·	distributions on our preferred units, debt service requirements and restrictions on distributions contained in our credit facility or future debt agreements;

·	interest payments;

·	fluctuations in our working capital needs;

·	general and administrative expenses; and

·	the amount of cash reserves, which we expect to be substantial, established by our general partner for the proper conduct of our business.

As a result of these factors, the amount of cash we distribute to our unitholders may fluctuate significantly from quarter to quarter and may be less than the any distribution that we have announced. For a description of additional restrictions and factors that may affect our ability to make cash distributions to our unitholders, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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. For example, market prices for natural gas in the United States have declined substantially from 2008 price levels, and the rapid development of shale plays throughout North America has contributed significantly to this trend. Lower prices also may reduce the amount of natural gas or oil that we can produce economically. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

·	domestic and foreign supply of and demand for oil and natural gas;

·	weather conditions and the occurrence of natural disasters;

·	overall domestic and global economic conditions;

·	political and economic conditions in oil and natural gas producing countries globally, including terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war;

·	actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

·	the effect of increasing liquefied natural gas, or LNG, deliveries to and exports from the United States;

·	the impact of the U.S. dollar exchange rates on oil and natural gas prices;

·	technological advances affecting energy supply and energy consumption, including improved drilling techniques for unconventional resource areas;

·	domestic and foreign governmental regulations and taxation;

·	the impact of energy conservation efforts;

·	the proximity, capacity, cost and availability of oil and natural gas pipelines and other transportation facilities;

·	the availability of refining capacity; and

·	the price and availability of alternative fuels.

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during 2012, the NYMEX–WTI oil price ranged from a high of $109.39 per Bbl to a low of $77.72 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $3.77 per MMBtu to a low of $1.82 per MMBtu. For the five years ended December 31, 2012, the NYMEX–WTI oil price ranged from a high of $145.31 per Bbl to a low of $30.28 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $13.31 per MMBtu to a low of $1.82 per MMBtu. Future decreases in the natural gas market price could have a negative impact on revenues, profitability, and cash flow. Declines in future natural gas market prices could also have a negative impact on our reserves values. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ‒ Critical Accounting Policies and Estimates for further discussion.

Our revenue, profitability and cash flow depend upon the prices of and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

·	limit our ability to enter into commodity derivative contracts at attractive prices;

·	negatively impact the value and quantities of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can economically produce;

·	reduce the amount of cash flow available for capital expenditures;

·	limit our ability to borrow money or raise additional capital; and

·	impair our ability to pay distributions to our unitholders.

If we raise our distribution levels in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during subsequent periods of lower commodity prices.

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 December 31, 2012 reserve report, the average decline rate for our existing proved developed producing reserves is approximately 11% for 2013, approximately 9% compounded average decline for the subsequent five years and approximately 9% 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 will reserve substantial amounts of cash each quarter to finance these expenditures over time. We estimate that an average annual capital expenditure of $68.0 million will enable us to maintain the current level of production from our assets through December 31, 2017. 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 may be unable to pay distributions at the minimum quarterly distribution rate from cash generated from operations and would therefore have 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 have to reduce our distributions to our unitholders.

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 our new credit facility and the issuance of debt and equity securities.

Our cash flows from operations and access to capital are subject to a number of variables, including:

·	our estimated proved oil and natural gas reserves;

·	the amount of oil, NGLs and natural gas we produce from existing wells;

·	the prices at which we sell our production;

·	the costs of developing and producing our oil and natural gas production;

·	our ability to acquire, locate and produce new reserves;

·	the ability and willingness of banks to lend to us; and

·	our ability to access the equity and debt capital markets.

The use of cash generated from operations to fund growth capital expenditures will reduce cash available for distribution to our unitholders. If the borrowing base under our 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.

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 derivative 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. In 2012, we entered into basis differential derivative contracts to reduce the impact of these differentials with respect to our production. The prices at which we enter into basis differential derivative contracts in the future will be dependent upon price differentials at the time we enter into these transactions, which may be substantially higher or lower than the current differentials. Accordingly, our differential hedging strategy may not protect us from significant increases in price differentials.

Future price declines of oil and natural gas 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 exploitation 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, delayed 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 derivative instruments, 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 the ceiling limitation calculation uses the SEC methodology to calculate the present value of future net cash flows from estimated proved reserves. If the net book value of our oil and natural gas properties exceeds our ceiling limitation, SEC regulations require us to impair or “write down” the book value of our oil and natural gas properties.

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 mitigating the impact of commodity price volatility from our cash flows, which could result in financial losses or could reduce our income.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we use commodity derivative contracts for a significant portion of our oil and natural gas production that could result in both realized and unrealized hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity derivative contracts. For example, some of the commodity derivative contracts we utilize are based on quoted market prices, which may differ significantly from the actual prices we realize in our operations for oil and natural gas. Our credit facility also limits the amount of commodity derivative contracts we can enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. In accordance with our hedging strategy, for 2013, and over a three-to-five year period at a given point in time, approximately 15% to 35% of our estimated total oil and natural gas production will not be covered by commodity derivative contracts. In addition, none of our estimated total NGL production is covered by commodity derivative contracts. See Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk for further details.

We have adopted a hedging strategy to reduce the impact to our cash flows from commodity price volatility. In 2012, we entered into basis differential derivative contracts to reduce the impact of differentials we experience in respect of our production. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our current and anticipated production over a three-to-five year period. As opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative contracts in connection with material increases in our estimated reserves and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of opportunities to modify our commodity and differential derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. However, our price hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under an obligation to enter into commodity and differential derivative contracts covering a specific portion of our production. The prices at which we enter into commodity and differential derivative contracts covering our production in the future will be dependent upon oil and natural gas prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.

In addition, our actual future production may be significantly higher or lower than we estimate at the time we enter into commodity and differential derivative contracts for such period. If the actual production is higher than estimated, we will have greater commodity price exposure than we intended. If the actual production is lower than the notional amount of our commodity derivative contracts, we might be forced to satisfy all or a portion of our commodity and differential derivative contracts without the benefit of the cash flow from our sale of the underlying physical commodity, substantially diminishing our liquidity. There may be a change in the expected differential between the underlying commodity price in the commodity derivative contract and the actual price received, which may result in payments to our derivative counterparty that are not offset by our receipt of higher prices from our production in the field.

As a result of these factors, our commodity derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows, which could adversely affect our ability to pay distributions to our unitholders.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.

It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs. In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

·	the level of oil and natural gas prices;

·	future production levels;

·	capital expenditures;

·	operating and development costs;

·	the effects of regulation;

·	the accuracy and reliability of the underlying engineering and geologic data; and

·	the availability of funds.

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our estimated proved reserves could change significantly. For example, if the prices used in our December 31, 2012 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 would have decreased by $364.4 million, from $1.6 billion to $1.2 billion.

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 and FASB guidance. 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 actual prices we receive for oil, natural gas and NGLs;

·	our actual operating costs in producing oil, natural gas and NGLs;

·	the amount and timing of actual production;

·	the amount and timing of our capital expenditures;

·	the supply of and demand for oil, natural gas and NGLs; and

·	changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with SEC and FASB guidance, 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.

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 27% of our 2012 production was derived from and 47% of our estimated proved reserves as of December 31, 2012 rely upon 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:

·	lower-than-expected production;

·	longer response times;

·	higher-than-expected operating and capital costs;

·	shortages of equipment; and

·	lack of technical expertise.

If any of these risks occur, it could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

The cost of developing, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated. Furthermore, our development and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

·	high costs, shortages or delivery delays of rigs, equipment, labor or other services or in obtaining water for hydraulic fracturing activities;

·	composition of sour gas, including sulfur and mercaptan content;

·	unexpected operational events and conditions;

·	reductions in oil and natural gas prices;

·	increases in severance taxes;

·	adverse weather conditions and natural disasters;

·	facility or equipment malfunctions and equipment failures or accidents, including acceleration of the deterioration of our facilities and equipment due to the highly corrosive nature of sour gas;

·	title problems;

·	pipe or cement failures and casing collapses;

·	compliance with environmental and other governmental requirements;

environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

·	lost or damaged oilfield development and service tools;

·	unusual or unexpected geological formations and pressure or irregularities in formations;

·	loss of drilling fluid circulation;

·	fires, blowouts, surface craterings and explosions;

·	uncontrollable flows of oil, natural gas, formation water or well fluids;

·	loss of leases due to incorrect payment of royalties; and

·	other hazards, including those associated with sour gas such as an accidental discharge of hydrogen sulfide gas, that could also result in personal injury and loss of life, pollution and suspension of operations.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and cash available for distribution to our unitholders.

Additionally, drilling, transportation and processing of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with the affected wellbore, contamination of soil, ground water and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences.

Our expectations for future drilling activities are planned to be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

We have identified drilling, recompletion and development locations and prospects for future drilling, recompletion and development. These drilling, recompletion and development locations represent a significant part of our future drilling and enhanced recovery opportunity plans. Our ability to drill, recomplete and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs and drilling results. Because of these uncertainties, we cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of estimated proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our estimated reserves, financial condition and results of operations.

Shortages of rigs, equipment and crews could delay our operations and reduce our cash available for distribution to our unitholders.

Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services and personnel. Shortages of, or increasing costs for, experienced development crews and oilfield equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues and reduce our cash available for distribution to our unitholders.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.

Our ability to grow and to increase distributions to our unitholders depends in part on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:

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

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

·	outbid by competitors.

If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions to our unitholders.

Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.

Even if we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:

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

·	an inability to successfully integrate the businesses we acquire;

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

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

·	the assumption of unknown liabilities, losses or costs including, for example, historical spills or releases for which we are not indemnified or for which our indemnity is inadequate;

·	the diversion of management’s attention from other business concerns;

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

·	facts and circumstances that could give rise to significant cash and certain non-cash charges;

·	unforeseen difficulties encountered in operating in new geographic areas; and

·	customer or key employee losses at the acquired businesses.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition, given time constraints imposed by sellers. Even a detailed review of records and assessment of 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 sells 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 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 of substantially greater size than ours. Those companies may be able to develop and acquire more properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

We may incur substantial additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to pay future distributions or execute our business plan.

We may be unable to pay the minimum quarterly distribution or the then-current distribution rate without borrowing under our 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 credit facility to pay distributions to our unitholders rather than to maintain or expand our operations. If we use borrowings under our 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.

We had $766.1 million of debt outstanding as of December 31, 2012. We have the ability to incur debt, including under our credit facility, subject to anticipated borrowing base limitations in our credit facility. The level of our future indebtedness could have important consequences to us, including:

·	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

·	covenants contained in our credit facility and future debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

·	we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to our unitholders; and

·	our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions to our unitholders, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all, which may have an adverse effect on our ability to make cash distributions.

Our credit facility and the indenture governing our senior notes 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 credit facility, the indenture governing our senior notes 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. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ‒ Liquidity and Capital Resources. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provision of our credit facility or indenture that is not cured or waived within the appropriate time periods, 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.

Our credit facility is reserve-based, and thus we are permitted to borrow under the credit facility in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. These borrowing base redeterminations are based on an engineering report with respect to our estimated natural gas, NGL and oil reserves, which will take into account the prevailing natural gas, NGL and oil prices at such time, as adjusted for the impact of our commodity derivative contracts. In the future, we may be unable to access sufficient capital under our credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

A future decline in commodity prices could result in a redetermination that lowers our borrowing base and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our 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 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. 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 not 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, we may not be able to achieve any production from these properties in a timely manner.

As of December 31, 2012, 11.6 MMBoe of our estimated proved reserves and 1.1 MMBoe of our estimated proved undeveloped reserves, or 12% of our estimated proved reserves and 5% of our estimated proved undeveloped reserves as determined by volume and by value based on standardized measure, were attributable to properties for which we were not the operator. As a result, the success and timing of drilling and development activities on such nonoperated properties depend upon a number of factors, including:

·	the nature and timing of drilling and operational activities;

·	the timing and amount of capital expenditures;

·	the operators’ expertise and financial resources;

·	the approval of other participants in such properties; and

·	the selection and application of suitable technology.

If drilling and development activities are not conducted on these properties or are not conducted on a timely basis, we may be unable to increase our production or offset normal production declines, or we will be required to write off the estimated proved reserves attributable thereto, any of which may adversely affect our production, revenues and results of operations and our cash available for distribution. Any such write-offs of our reserves could reduce our ability to borrow money and could adversely impact our ability to pay distributions on the common units.

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. See Part I, Item 1. Business ‒ Environmental and Occupational Safety and Health 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 and regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the CAA that establish for GHG emissions from certain large stationary sources and that may require the installation of “best available control technologies” established by the states or EPA. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming years, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations 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. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. See Part I, Item 1. Business ‒ Environmental and Occupational Safety and Health Matters for more information.

Our operations are subject to environmental and occupational health and 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, regional, state and local laws and regulations governing the discharge of materials into the environment, occupational 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 as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations and due to historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several or 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 well drilling, construction, completion or water management activities, or 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. See Part I, Item 1. Business ‒ Environmental and Occupational Safety and Health Matters 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 regulations. If existing laws and regulations governing such third party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. See Part I, Item 1. Business ‒ Environmental and Occupational Safety and Health Matters and ‒ 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 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 in 2010 adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010, and requires the Commodity Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap”, “security-based swap”, “swap dealer” and “major swap participant”. The Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects. The Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities into a separate entity, which may not be as creditworthy as the current counterparty. The Act and any implementing regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), 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 or to make 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 instruments 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, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. In addition, congress from time to time has considered adopting legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states, including Louisiana and Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In the event new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

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.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations sectors, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cyber attacks on our customer and employee data may result in a financial loss and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

Risks Inherent in an Investment in Us

Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.

Our general partner has control over all decisions related to our operations. Our general partner is owned 50% by an entity controlled by Mr. Neugebauer and Mr. VanLoh, who are directors of our general partner and also managing partners of Quantum Energy Partners, and 50% by an entity controlled by Mr. Smith, our Chief Executive Officer, a director of our general partner and Chief Executive Officer and a director of Quantum Resources Management and Mr. Campbell, our President and Chief Operating Officer, a director of our general partner and President, Chief Operating Officer and a director of Quantum Resources Management. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, certain directors and officers of our general partner are directors or officers of affiliates of our general partner, including Quantum Resources Management and Quantum Energy Partners, and certain of our executive officers and directors will continue to have economic interests, investments and other economic incentives in funds affiliated with Quantum Energy Partners. Conflicts of interest may arise in the future between the Fund, Quantum Energy Partners and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. 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:

as of March 5, 2013, the Fund owned preferred and common units representing a 29.3% limited partner interest in us. In addition, the general partner of the Fund is owned 72% by an entity controlled by Messrs Neugebauer, VanLoh, Smith and Campbell. On February 22, 2013, the general partner elected to convert the full 80% of the fourth quarter 2012 management incentive fee to which it was entitled and, on March 4, 2013, received 6,133,558 Class B units, which are immediately convertible into common units at the election of our general partner;

neither our partnership agreement nor any other agreement requires the Fund, Quantum Energy Partners or their respective affiliates (other than our general partner) to pursue a business strategy that favors us. The directors and officers of the Fund, Quantum Energy Partners and their respective affiliates (other than our general partner) have a fiduciary duty to make these decisions in the best interests of their respective equity holders, which may be contrary to our interests;

·	our general partner is allowed to take into account the interests of parties other than us, such as the owners of our general partner, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

the Fund, Quantum Energy Partners and their affiliates are not limited in their ability to compete with us, including with respect to future acquisition opportunities, and are under no obligation to offer assets to us except for the obligations of the Fund and its general partner under our omnibus agreement;

·	many of the officers of our general partner who will provide services to us will devote time to affiliates of our general partner, including Quantum Resources Management and Quantum Energy Partners, and may be compensated for services rendered to such affiliates;

our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

·	our general partner has entered into a services agreement with Quantum Resources Management, pursuant to which Quantum Resources Management will operate our assets and perform other administrative services for us. Quantum Resources Management has similar arrangements with affiliates of the Fund;

beginning January 1, 2013, our general partner determines which costs, including allocated overhead, incurred by it and its affiliates, including Quantum Resources Management, are reimbursable by us. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us;

·	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

·	our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

·	our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

·	our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including Quantum Resources Management and the Fund; and

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

See Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence.

The Fund, Quantum Energy Partners and other affiliates of our general partner will not be limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

Our partnership agreement provides that the Fund and Quantum Energy Partners and their respective affiliates are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, except for the limited obligations of the Fund described below with respect to our omnibus agreement, the Fund and Quantum Energy Partners and their respective 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 is only obligated to offer us the first option to acquire 25% of each acquisition that becomes available to the Fund, so long as at least 70% of the allocated value (as determined in good faith by the Fund) is attributable to proved developed producing reserves. The terms of our omnibus agreement require the Fund to give us a preferential opportunity to bid on any oil or natural gas properties that the Fund intends to sell only if such properties are at least 70% proved developed producing reserves (as determined in good faith by the Fund). These provisions of the omnibus agreement will expire December 22, 2015.

The Fund and Quantum Energy Partners are established participants in the oil and natural gas industry, and have resources greater than ours, factors which may make it more difficult for us to compete with the Fund and Quantum Energy Partners with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for d


Delaware (State of other jurisdiction of incorporation or organization)	90-0613069 (I.R.S. Employer Identification No.)

1401 McKinney Street, Suite 2400, Houston, Texas (Address of principal executive offices)	77010 (Zip Code)


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