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TABLE OF CONTENTS

PART I

Item 1.	Business	9
Item 1A.	Risk Factors	28
Item 1B.	Unresolved Staff Comments	54
Item 2.	Properties	54
Item 3.	Legal Proceedings	54
Item 4.	Mine Safety Disclosures	54

PART II

Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases
	of Equity Securities	55
Item 6.	Selected Financial Data	60
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	64
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	85
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	86
Item 9A.	Controls and Procedures	87
Item 9B.	Other Information	88

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	89
Item 11.	Executive Compensation	96
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
	Matters	108
Item 13.	Certain Relationships and Related Transactions, and Director Independence	111
Item 14.	Principal Accounting Fees and Services	114

PART IV

Item 15.	Exhibits, Financial Statement Schedules	116

Signatures		119

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. This definition has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

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 costs and, 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;

“ETSWDC” refers to East Texas Salt Water Disposal Company, a saltwater disposal business in which we acquired a majority interest as part of the 2013 East Texas Acquisition;

“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.

CAUTIONARY STATEMENT REGARDING FORWARD–LOOKING INFORMATION

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 NGLs reserves;

technology;

realized oil, natural gas and NGLs 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 Part I, Item 1. Business, Part I, Item 1A. Risk Factors, Part II, 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 or any 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 Part I, 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 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, 2013, our total estimated proved reserves were approximately 109.1 MMBoe, of which approximately 77% were oil and NGLs and 85% were classified as proved developed reserves. As of December 31, 2013, our estimated proved reserves had a standardized measure of $2.0 billion. As of December 31, 2013, we produced from 5,668 gross (3,270 net) wells across our properties, with an average working interest of 57.7%.

Oil and natural gas reserve information included in this Form 10-K is derived from our reserve report prepared by Netherland, Sewell & Associates, Inc., our independent reserve engineers for the year ended December 31, 2013 and Miller and Lents, LTD, our independent reserve engineers for the years ended December 31, 2012 and 2011. The following table summarizes information about our proved oil and natural gas reserves by geographic region as of December 31, 2013 and our average net production for the year ended December 31, 2013:


	Estimated Net Proved Reserves						Production
	Oil &		Natural			Standardized	Average Net Production
	Cond.	NGLs	Gas			Measure (1)		% of	%	Producing Wells
	(MBbls)	(MBbls)	(MMcf)	MBoe		($ millions)	Boe/d	Total	Oil and NGLs	Gross	Net
Ark-La-Tex	29,430.0	4,721.4	90,726.7	49,272.5		858.6	6,799	38	59	2,486	2,161
Permian Basin	23,627.0	3,337.0	40,501.9	33,714.3	$	611.6	5,962	33	73	2,720	855
Gulf Coast	18,024.1	2,396.2	2,668.6	20,865.1		498.0	3,677	21	97	63	50
Mid-Continent	1,620.7	321.4	17,844.0	4,916.1		68.0	1,384	8	44	381	186
Michigan	313.5	-	-	313.5		7.2	82	-	100	18	18
Total	73,015.3	10,776.0	151,741.2	109,081.5	$	2,043.4	17,904	100	71	5,668	3,270

⁽¹⁾

As of December 31, 2013 our standardized measure was $2.0 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.

Recent Developments

GP Buyout Transaction

On March 2, 2014, we completed a transaction related to our general partner interest pursuant to a Contribution Agreement, by and among the Partnership, the general partner, QR Holdings (QRE), LLC (“QRH”) and QR Energy Holdings, LLC (“QREH” and, together with QRH, the “QR Parties”), the former owners of our general partner, pursuant to which (i) the general partner reclassified its 0.1% general partner interest in the Partnership, formerly represented by 51,036 general partner units, in exchange for a non-economic general partner interest, (ii) the QR Parties contributed 100% of the limited liability company interests of the general partner to the Partnership, and (iii) the partnership agreement was amended, to, among other things, (a) terminate the management incentive fee and provide for the future issuance of up to 11.6 million Class B units, subject to certain tests, to the QR Parties and (b) provide for the election of all of the members of the board of directors of the general partner by our limited partners beginning in June 2015 (the “GP Buyout Transaction”).

East Texas Acquisition

On August 6, 2013, we closed the acquisition of primarily oil properties located in East Texas (the “2013 East Texas Acquisition”) from a private seller for $107.8 million in cash subject to customary purchase price adjustments. The acquired properties (the “2013 East Texas Properties”) had estimated proved reserves of 5.9 MMBoe as of the acquisition date utilizing SEC case pricing. The acquisition had an effective date of June 1, 2013. In addition, the 2013 East Texas Acquisition included a controlling interest in ETSWDC. See Part II, Item 8. Financial Statements and Supplementary Data – Note 4 – Acquisitions for further details.

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 years ended December 31, 2012 and 2011, 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 11 – Commitments and Contingencies and Note 2 – Summary of 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 or monthly cash distributions to our unitholders and, over time, to increase our quarterly or monthly 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 (the“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 the Omnibus Agreement (the ”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 29.2% limited partner interest in us including all of our Class C preferred units as of March 2, 2014. 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, 2013, 2012 and 2011 and our reserves as of December 31, 2013, 2012 and 2011 for each of our areas:


2013		Ark-La-Tex			Permain Basin			Gulf Coast			Mid-Continent			Michigan (1)			Total
Production:
Oil (MBbl)		1,127			1,297			1,174			195			30			3,823
Natural Gas (MMcf)		6,067			3,513			223			1,694			-			11,497
NGL (MBbl)		344			293			131			28			-			796
MBoe		2,482			2,176			1,342			505			30			6,535
Boe/d		6,799			5,962			3,677			1,384			82			17,904

Average sales price per unit:
Oil (per Bbl)	$	100.68		$	92.69		$	104.29		$	95.19		$	90.13		$	98.68
Natural gas (per Mcf)	$	3.49		$	3.59		$	3.70		$	3.75		$	-		$	3.49
Natural gas liquids (per Bbl)	$	37.40		$	29.37		$	52.69		$	37.10		$	-		$	36.96

Lease operating expense (per Boe)	$	17.07		$	21.38		$	31.87		$	18.44		$	43.83		$	21.72

Reserves:
MBoe		49,272.5			33,714.3			20,865.1			4,916.1			313.5			109,081.5
Liquids		69	%		80	%		98	%		40	%		100	%		77	%
Proved Developed		89	%		71	%		95	%		100	%		100	%		85	%
Proved Operated		100	%		77	%		96	%		73	%		100	%		91	%
Total Proved		45	%		31	%		19	%		5	%		-	%		100	%

2013 Actual Capital Expenditures	$	27,304		$	48,380		$	21,654		$	1,027		$	172		$	98,537
2014 Expected Capital Budget (2)	$	36,600		$	40,000		$	23,300		$	1,700		$	-		$	101,600


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

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

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

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


2011		Ark-La-Tex			Permian Basin			Gulf Coast			Mid-Continent			Michigan (1)			Total
Production:
Oil (MBbl)		185			1,120			951			238			-			2,594
Natural Gas (MMcf)		7,886			5,188			309			1,723			-			15,106
NGL (MBbl)		158			370			126			26			-			680
MBoe		1,657			2,455			1,129			551			-			5,792
Boe/d		4,540			6,726			3,093			1,509			-			15,868

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

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

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

⁽¹⁾

Acquired through the 2012 Prize Acquisition.

⁽²⁾

The 2014 Expected Capital Budget is our current expectation and is subject to change as conditions warrant.

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 2013, we acquired an additional interest in the East Texas Oil Field. In 2013, we invested $27.3 million in capital in this area, primarily on recompletions, returning wells to production, artificial lift enhancements and facility upgrades in the Dorcheat Macedonia, East Texas Oil Field, Gladewater, Neches and Shongaloo fields. In 2013, we drilled 2 net (2 gross) wells in the Ark-La-Tex area, both in the East Texas Oil Field.

The East Texas Oil Field is a significant field which constituted approximately 17% of our estimated proved reserves as of December 31, 2013. The Partnership’s production from the East Texas Oil Field is presented for the years ended December 31, 2013, 2012, and 2011.


	2013 (1)	2012 (2)	2011
Production:
Oil (MBbl)	602.3	32.6	-
Gas (MMcf)	-	25.2	-
NGL (MBbl)	20.6	-	-
MBoe	622.9	36.8	-
Boe/d	2,403.5	1,174.7	-

⁽¹⁾

The 2012 volumes and calculations represent the first 28 days of production from the December 4, 2012 acquisition date of the 2012 East Texas Acquisition.

⁽²⁾

The 2013 volumes and calculations represent a full year of the 2012 East Texas Acquisition, five months of the 2013 East Texas Acquisition, and the partial effect of various small acquisitions completed in the fourth quarter of 2013.

During 2014, we expect our Ark-La-Tex capital budget to be approximately $36.6 million, which is expected to be spent on development drilling programs in the Dorcheat Macedonia, East Texas Oil Field and Overton fields, and on continued well reactivations, recompletions, artificial lift enhancements, workovers and facility upgrades, primarily in the East Texas Oil Field, Gladewater, and Neches fields.

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 2013, we invested $48.4 million in capital in the Permian Basin, primarily on development drilling in the Blineberry-Drinkard, Garden City South, Turner Gregory, and Wasson fields. In 2013, we drilled or participated in the drilling of 18 net (66 gross) wells in the Permian Basin. Other Permian Basin capital was spent on recompletions, artificial lift enhancements and facility upgrades, primarily in our Fuhrman Mascho, East Corrigan, G P M, North Cowden and Turner Gregory fields.

During 2014, we expect to invest approximately $40 million in capital in the Permian Basin, primarily on further development drilling, recompletions, workovers, and facility upgrades.

Gulf Coast

The Gulf Coast area includes properties located in southern Alabama, southeast Texas and Florida. These properties produce from formations such as the Yegua Sand and Smackover Carbonate at depths ranging from 8,000 to 15,000 feet. During 2013, we invested $21.7 million in this area, primarily on well work and facility upgrades at the Jay Field.

The Jay Field is a significant field which constituted approximately 18% of our estimated proved reserves as of December 31, 2013. The Partnership’s production from the Jay Field is presented for the years ended December 31, 2013, 2012, and 2011.


	2013	2012	2011
Production:
Oil (MBbl)	1,144.1	1,026.8	918.2
Gas (MMcf)	-	0.4	1.1
NGL (MBbl)	110.4	109.8	112.7
MBoe	1,254.5	1,136.7	1,031.1
Boe/d	3,437.0	3,105.6	2,824.9

During 2014, we expect our Gulf Coast capital budget to be approximately $23.3 million, primarily for well work, workovers, and plant and facility upgrades at the Jay field.

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 2013, we invested $1.0 million in capital in this area, primarily on well work and facility upgrades in our Adams Ranch and Apache fields, and in the drilling of less than 1 net (2 gross) wells in the Mills Ranch field.

During 2014, we expect our Mid-Continent capital budget to be approximately $1.7 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 2014, we plan to continue evaluating 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 annually by our independent third-party reserve engineers, Netherland, Sewell & Associates, Inc., for the year ended December 31, 2013 and Miller and Lents, Ltd., for the years ended December 31, 2012 and 2011.

Our internal professional staff works closely with our independent third-party reserve engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide our independent third-party reserve engineers 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 Vice President of Strategic Planning 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. He has more than 20 years of industry experience working in a wide variety of technical and supervisory positions. His background includes the preparation and/or review of reserves at Quantum Resources Management, Exxon, Chevron, Unocal, Huber Energy and Credo Petroleum. He has a B.S. in Chemical Engineering from Texas A&M University, an MBA from the UCLA Anderson School of Management, and is a registered professional engineer in California.

Netherland, Sewell & Associates, Inc. The reserves estimates shown herein as of December 31, 2013 have been independently evaluated by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Connor Riseden and Mr. Mike Norton. Mr. Riseden has been practicing consulting petroleum engineering at NSAI since 2006. Mr. Riseden is a Licensed Professional Engineer in the State of Texas (No. 100566) and has over 12 years of practical experience in petroleum engineering, with over 12 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 2001 with a Bachelor of Science Degree in Petroleum Engineering and from Tulane University in 2005 with a Master of Business Administration Degree. Mr. Norton has been practicing consulting petroleum geology at NSAI since 1989. Mr. Norton is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441) and has over 34 years of practical experience in petroleum geosciences, with over 24 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Miller & Lents. Miller & Lents, Ltd is an independent oil and natural gas consulting firm. The preparation of the Miller & Lents, Ltd. reserve report as of December 2012 and 2011 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.

No director, officer, or key employee of Netherland, Sewell & Associates, Inc. or Miller & Lents, Ltd. has any financial ownership in us, Quantum Resources Management, the Fund or any of their respective affiliates. Compensation for the required investigations and preparation of third party reserve reports are not contingent upon the results obtained and reported, and the third party reserve engineers have not performed other work for Quantum Resources Management, the Fund or us that would affect its objectivity.

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, 2013 based on reserve reports prepared by Netherland, Sewell & Associates, Inc. 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)
Ark-La-Tex
Developed	27,845.4	4,003.1	71,435.3	43,754.4	$	817,689
Undeveloped	1,584.6	718.3	19,291.4	5,518.1		40,950
Total	29,430.0	4,721.4	90,726.7	49,272.5	$	858,639

Permian Basin
Developed	14,622.0	2,907.5	38,253.2	23,905.0	$	443,326
Undeveloped	9,005.0	429.5	2,248.7	9,809.3		168,280
Total	23,627.0	3,337.0	40,501.9	33,714.3	$	611,606

Gulf Coast
Developed	17,089.9	2,272.5	2,668.6	19,807.2	$	474,560
Undeveloped	934.2	123.7	-	1,057.9		23,414
Total	18,024.1	2,396.2	2,668.6	20,865.1	$	497,974

Mid-Continent
Developed	1,620.7	321.4	17,844.0	4,916.1	$	67,960
Undeveloped	-	-	-	-		-
Total	1,620.7	321.4	17,844.0	4,916.1	$	67,960

Michigan
Developed	313.5	-	-	313.5	$	7,204
Undeveloped	-	-	-	-		-
Total	313.5	-	-	313.5	$	7,204

Total
Developed	61,491.5	9,504.5	130,201.1	92,696.2	$	1,810,739
Undeveloped	11,523.8	1,271.5	21,540.1	16,385.3		232,645
Total	73,015.3	10,776.0	151,741.2	109,081.5	$	2,043,384

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 our 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 245 proved undeveloped locations, including 69 injection wells for secondary and tertiary recovery operations.

We assess our PUD reserves on a semiannual basis. At December 31, 2013, we had 16,385 MBoe, or 15% of total proved reserves, of consolidated PUD reserves – a net decrease of 8,164 MBoe from our prior year-end PUD reserves. In 2013, we spent approximately $32 million to convert 740 MBoe of our prior year-end PUD reserves to proved developed reserves. As a result of revised technical and economic assessments done in 2013, our prior year-end PUD reserves were reduced by approximately 9,039 MBoe, while approximately 1,615 MBoe of new PUD reserves were added in 2013 through our drilling programs, optimization efforts and acquisitions.

In our December 31, 2013 reserve report, the amounts estimated to be spent over the next five years to develop our consolidated PUD reserves are $215 million or an average of $43 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 16,385 MBoe of PUD reserves at December 31, 2013, 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, 2013.


	Oil		Natural Gas
	Gross	Net	Gross	Net
Operated	2,747	2,620	712	511
Non-operated	1,908	58	301	82
Total	4,655	2,678	1,013	593

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 47.5% on average. As of December 31, 2013, all of our leases are held by production except 2,640 gross and net acres, subject to continuous drilling programs.

The following table sets forth information as of December 31, 2013 relating to our leasehold acreage. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.


	Developed Acreage
	Gross	Net
Ark-La-Tex	104,661	64,429
Permian Basin	96,391	44,836
Gulf Coast	16,990	14,903
Mid-Continent	111,435	52,565
Michigan	2,840	2,840
Total	332,317	179,573

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 development wells drilled and completed by us 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, 2013, we had drilling activities in progress at one field, and had 3 wells drilled but not yet completed. During 2013, we drilled one well that was a dry hole due to mechanical failure.


	Year Ended December 31,
	2013		2012		2011
	Gross	Net	Gross	Net	Gross	Net
Productive	69	19	93	47	88	11
Dry	1	1	-	-	-	-
Total	70	20	93	47	88	11

Operations

General

We operated approximately 93% of our assets as determined by value, based on standardized measure as of December 31, 2013. 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 non-operating partners a contractual administrative overhead charge for operating the wells. Some of our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies.

Administrative Services Fee

Beginning on January 1, 2013, QRM was 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 includes 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 has discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.

Prior to January 1, 2013, QRM 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 statements of operations.

For a detailed description of the administrative services fee paid to QRM 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:



	December 31, 2013		December 31, 2012		December 31, 2011
Customer A	27	%	33	%	29	%
Customer B	21	%	13	%	(1)
Customer C	17	%	(1)		(1)
Customer D	(1)		12	%	11	%
Customer E	(1)		(1)		12	%

⁽¹⁾

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

Customer A, Customer B, and Customer C 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, basis 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

The demand for natural gas generally, but not always, 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. Periodic storms in the winter may also 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. Numerous governmental entities, including the U.S. Environmental Protection Agency, or EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. 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 sanctions, including 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, or 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 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 or natural resources or for personal injuries. 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 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 and Subsurface Injections

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 and 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.

Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing

subsurface formations. The disposal of oil and natural gas wastes into underground injection wells are subject to the Safe Drinking Water Act, as amended, or SDWA, and analogous state laws. The Underground Injection Well Program under the SDWA requires that we obtain permits from the EPA or analogous state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities that may be injected, and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for alternative water supplies, property damages and personal injuries. While we believe that we have obtained the necessary permits from the applicable regulatory agencies for our underground injection wells and that we are in substantial compliance with applicable permit conditions and federal and state rules, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations, which costs could be significant. Furthermore, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.

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 SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and issued revised permitting guidance in February 2014 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 in the Semi-annual Regulatory Agenda published on July 3, 2013, the agency continues to project the issuance of an Advance 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 SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states where we operate, including Louisiana, New Mexico, Oklahoma and Texas 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. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. 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 draft 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 in 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014.Also, in May 2013, the federal Bureau of Land Management, or BLM, published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet

appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA 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.

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, in 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. In addition, 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 and from pneumatic controllers and storage vessels. We currently do not believe that compliance with these requirements has a material adverse effect on our results of operations or financial condition.

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 that exceed GHG emission threshold levels. 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.

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. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Endangered Species Act Considerations

The Endangered Species Act, as amended, or ESA, and analogous state laws may impact exploration, development and production activities on public or private lands. These laws provide broad protections 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. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. 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 numerous 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.

State Regulation

The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also

regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws has 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, 2013, Quantum Resources Management had 355 employees, including 16 engineers, 7 geologists and 22 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 Part I, Item 1. Business and Part I, 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.

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, NGLs 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, indenture 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 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 oil or natural gas 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 2013, the NYMEX–WTI oil price ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $4.52 per MMBtu to a low of $3.08 per MMBtu. For the five years ended December 31, 2013, the NYMEX–WTI oil price ranged from a high of $113.39 per Bbl to a low of $34.03 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $7.51 per MMBtu to a low of $1.82 per MMBtu. Future decreases in the oil or natural gas market price could have a negative impact on revenues, profitability, and cash flow. Declines in future oil and 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, 2013 reserve report, the average decline rate for our existing proved developed producing reserves is approximately 10% for 2014, approximately 8% compounded average decline for the subsequent five years and approximately 7% 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 $72.0 million will enable us to maintain the current level of production from our assets through December 31, 2018. 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, NGLs and natural gas;

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 2013, 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 2014, 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 2013, 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, a hypothetical 10% decrease in the unweighted arithmetic average first day of-the-month prices for the prior 12 month average of oil prices used in our December 31, 2013 reserve report would cause the standardized measure of our estimated proved reserves as of that date to decrease by $301 million, from $2.04 billion to $1.74 billion, and a hypothetical 10% decrease in the 12 month average of natural gas prices would cause the standardized measure of our estimated proved reserves to decrease by $24 million, from $2.04 billion to $2.02 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 39% of our 2013 production was derived from and 41% of our estimated proved reserves as of December 31, 2013 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 fully assess 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 $911.6 million of debt outstanding as of December 31, 2013. 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 affect 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, 2013, 10.1 MMBoe of our estimated proved reserves and 0.4 MMBoe of our estimated proved undeveloped reserves, or 9% of our estimated proved reserves as determined by volume (7% as determined by value based on standardized measure) and 3% 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 PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources and that may require the installation of “best available control technologies” for new or modified sources that exceed GHG emission threshold levels. 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. In addition, our operations include disposal operations into injection wells that pose risks of environmental liability, including leakage from the wells to surface or subsurface soils, surface water or groundwater. 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 results of operations, competitive position or financial condition. For example, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells; if new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position. 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 could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. Dodd-Frank Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions on us is uncertain at this time.

Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The full impact of Dodd-Frank Act and related regulatory requirements on our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, 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 or increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of Dodd-Frank Act and regulations implementing Dodd-Frank Act, 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.

Finally, Dodd-Frank Act 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 Dodd-Frank Act and implementing 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 issued revised permitting guidance in February 2014 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 in the Semi-annual Regulatory Agenda published on July 3, 2013, the agency continues to project the issuance of an Advance 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, New Mexico, Oklahoma 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.

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 draft 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 in 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014. Also, in May 2013, the BLM published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. 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 SDWA or other regulatory mechanisms.

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 adversely affect 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

The Fund, Quantum Energy Partners and their respective affiliates 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 distribution to our unitholders. See Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence for more information.

Neither we nor our general partner have any employees and we rely solely on the employees of Quantum Resources Management to manage our business. Quantum Resources Management will also provide substantially similar services to the Fund, and thus will not be solely focused on our business.

Neither we nor our general partner have any employees and we rely solely on Quantum Resources Management to operate our assets. Our general partner has entered into a Services Agreement with Quantum Resources Management, pursuant to which Quantum Resources Management has agreed to make Quantum Resources Management’s personnel available to our general partner in a manner that will allow us to carry on our business in the same manner in which it was carried on by our Predecessor.

Quantum Resources Management provides substantially similar services to the Fund. Should Quantum Energy Partners form other funds, Quantum Resources Management may enter into similar arrangements with those new funds. Because Quantum Resources Management provides services to us that are substantially similar to those provided to the Fund and, potentially, other funds, Quantum Resources Management may not have sufficient human, technical and other resources to provide those services at a level that Quantum Resources Management would be able to provide to us if it did not provide those similar services to the Fund and those other funds. Additionally, Quantum Resources Management may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of the Fund or other funds. There is no requirement that Quantum Resources Management favor us over the Fund or other funds in providing its services. If the employees of Quantum Resources Management and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

The former owners of our general partner are entitled to receive Class B units in the future upon the achievement of certain criteria.

Following the GP Buyout Transaction, the former owners of our general partner are entitled to receive up to an aggregate of 11.6 million Class B units in up to four annual installments during the next six calendar years, beginning with respect to the year ending December 31, 2014. The former owners are entitled to receive an annual installment of such units with respect to any calendar year in which we pay a distribution of $0.4744 per unit with respect to each quarter, achieved a Distribution Coverage Ratio (as defined in our Partnership Agreement) for the year of at least 1.0 and achieve a Total Debt to EBITDAX (as defined in our Partnership Agreement) of no greater

than 4.0 for each quarter during such year, unless any excess has been approved by the conflicts committee of our general partner. The Class B units have the same rights, preferences and privileges of our common units and are entitled to the same cash distributions per unit as our common units, except in liquidation where distributions are made in accordance with the respective capital accounts of the units and are convertible into an equal number of common units at the election of the holder. These Class B units may be issued as incentives without any corresponding increase in the cash distributions we pay to our unitholders, and any such Class B units issued to the former owners of our general partner will not be subject to forfeiture should we fail to meet the issuance criteria in future periods.

Many of the directors and officers who have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

To maintain and increase our levels of production, we will need to acquire oil and natural gas properties. Several of the officers and directors of our general partner, who are responsible for managing our operations and acquisition activities, hold similar positions with other entities that are in the business of identifying and acquiring oil and natural gas properties. For example, Mr. Smith is the Chief Executive Officer and a director of our general partner and Chief Executive Officer and a director of Quantum Resources Management and Mr. Campbell is the President and Chief Operating Officer and a director of our general partner and President, Chief Operating Officer and a director of Quantum Resources Management. Mr. Smith and Mr. Campbell manage the Fund, and the Fund is also in the business of acquiring oil and natural gas properties. In addition Mr. Neugebauer and Mr. VanLoh, who are directors of our general partner are also managing partners of Quantum Energy Partners. Mr. Burgher, the Chief Financial Officer of our general partner, serves on the board of a Quantum Energy Partners portfolio company. Quantum Energy Partners is in the business of investing in oil and natural gas companies with independent management, and those companies also seek to acquire oil and natural gas properties. Mr. Neugebauer and Mr. VanLoh are also directors of several oil and natural gas producing entities that are in the business of acquiring oil and natural gas properties. Mr. Wolf, the Chairman of the board of directors of our general partner, is also the chief executive officer and a director of the general partner of the Fund and is on the board of directors of other companies who also seek to acquire oil and natural gas properties. Several officers of our general partner continue to devote significant time to the other businesses, including businesses to which Quantum Resources Management provides management and administrative services. The existing positions held by these directors and officers may give rise to fiduciary duties that are in conflict with fiduciary duties they owe to us. We cannot assure our unitholders that these conflicts will be resolved in our favor. As officers and directors of our general partner these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present them to us. For a complete discussion of our management’s business affiliations and the potential conflicts of interest of which our unitholders should be aware, see Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence.

Our right of first offer to purchase certain of the Fund’s producing properties and right to participate in acquisition opportunities with the Fund are subject to risks and uncertainty, and thus may not enhance our ability to grow our business.

Under the terms of our omnibus agreement, the Fund 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. Additionally, the Fund has committed to offer us the first option to acquire at least 25% of each acquisition available to it, so long as at least 70% of the allocated value is attributable to proved developed producing reserves. The consummation and timing of any future transactions pursuant to either such right with respect to any particular acquisition opportunity will depend upon, among other things, our ability to negotiate definitive agreements with respect to such opportunities and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future transactions pursuant to these rights. Additionally, the Fund is under no obligation to accept any offer made by us to purchase properties that it may offer for sale. Furthermore, for a variety of reasons, we may decide not to exercise these rights when they become available, and our decision

will not be subject to unitholder approval. The contractual obligations under the omnibus agreement automatically terminate on December 22, 2015. See Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence.

We reimburse Quantum Resources Management for all allocable expenses it incurs on our behalf in its performance under the Services Agreement, which amounts may be substantial.

Beginning on January 1, 2013, Quantum Resources Management was entitled to a quarterly administrative services fee based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. The fee includes 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. These fees will be included in general and administrative expenses in our consolidated statement of operations. Quantum Resources Management will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.

Units held by persons who our general partner determines are not eligible holders will be subject to redemption.

To comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means:

a citizen of the United States;

a corporation organized under the laws of the United States or of any state thereof;

a public body, including a municipality; or

an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.

Onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder, will run the risk of having their common units redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our general partner will be required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

Maintenance capital expenditures are those capital expenditures required to maintain our long-term asset base, including expenditures to replace our oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will

have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation. In addition, the ability of our general partner to receive a management incentive fee is based on the amount of cash distributed to our unitholders from operating surplus, which in turn is partially dependent upon its determination of our estimated maintenance capital expenditures. If estimated maintenance capital expenditures are lower than actual maintenance capital expenditures, then our general partner may be entitled to the management incentive fee at times when cash distributions to our unitholders would not have come from operating surplus if operating surplus was reduced by actual maintenance capital expenditures.

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement;

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith;

generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above.

We may not make cash distributions during periods when we record net income.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.

Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. For example, in October 2011, we completed an acquisition of oil and natural gas properties from the Fund and issued preferred units as a portion of the transaction consideration that rank prior to our common units as to distributions upon liquidation. These preferred units are convertible into common units upon the achievement of certain common unit trading price criteria prior to the second anniversary of their issuance, and are convertible without having to satisfy any such criteria following the second anniversary of their issuance. See Part II, Item 8. Financial Statements and Supplementary Data – Note 2 –Summary of Significant Accounting Policies for information on the terms of our preferred units. On February 22, 2013, our general partner elected to convert the full 80% of the fourth quarter 2012 management incentive fee to which it was formally entitled and, on March 4, 2013, received 6,133,558 Class B units, which are convertible into common units at their owners’ election. Additionally, following the GP Buyout Transaction, the former owners of our general partner are entitled to receive up to 11.6 million Class B units in up to four installments over a six calendar year period upon achievement of certain criteria. See Part I, Item 1A. “Business - Recent Developments – GP Buyout Transaction.” As of March 2, 2014, the Fund and the general partner collectively owned a 36.4% limited partner interest in us.

The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

our unitholders’ proportionate ownership interest in us will decrease;

the amount of cash available for distribution on each unit may decrease;

the ratio of taxable income to distributions may increase;

the relative voting strength of each previously outstanding unit may be diminished; and

the market price of our common units may decline.

Certain of our investors may sell units in the public market, which could reduce the market price of our outstanding common units.

We have agreed to file a registration statement on Form S-3 to cover sales by the Fund of all common units it currently owns and common units issuable upon conversion of our outstanding Class C preferred units. If the Fund or any transferee were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Our partnership agreement restricts the limited voting rights of unitholders, other than our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.

Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of common units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

Our general partner has a call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. As of March 2, 2014, the Fund owned a 29.2% limited partner interest in us including preferred and common units. All of our subordinated units converted to common units on December 22, 2012, and our preferred units may be converted into common units upon the achievement of certain common unit trading price criteria prior to the second anniversary of their issuance, and are convertible without having to satisfy any such criteria following the second anniversary of their issuance. See Part II, Item 8. Financial Statements and Supplementary Data – Note 2 – Summary of Significant Accounting Policies for information on the terms of our preferred units.

If we distribute cash from capital surplus, which is analogous to a return of capital, the target distribution relating to our general partner’s management incentive fee will be proportionately decreased.

Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes and any payments in respect of the management incentive fee, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in the glossary and generally would result from cash received from nonoperating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 99.9% to our unitholders and 0.1% to our general partner, and will result in a decrease in the Target Distribution used in calculating the management incentive fee paid to our general partner, which may have the effect of increasing the likelihood that our general partner would earn the management incentive fee in future periods.

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if it was a general partner if:

a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Our unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the Target Distribution may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that would affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units. Any modification to the federal income tax laws may be applied retroactively and could

make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

Legislation has been proposed in a prior session of Congress that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

If the IRS contests any of the federal income tax positions we take, the market for our units may be adversely affected, and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders are treated as partners to whom we allocate taxable income, which could be different in amount than the cash we distribute, our unitholders may be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our units could be more or less than expected.

If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Because distributions in excess of their allocable share of our total net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion and IDC recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.

Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be subject

to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons and each non-U.S. person will be required to file federal tax returns and pay tax on their share of our taxable income. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units.

We will treat each purchaser of units as having the same tax benefits without regard to the units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

Because we cannot match transferors and transferees of units and because of other reasons, we will adopt depreciation, depletion, and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the securities loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical

termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the Partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

As a result of investing in our units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future even if such unitholders do not live in those jurisdictions. Our unitholders likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We initially will own property and conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. We may own property or conduct business in other states or foreign countries in the future. It is a unitholder’s responsibility to file all U.S. federal, state and local tax returns.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Information regarding our properties is contained in Part I, Item 1. Business – Our Areas of Operation and – Our Oil and Natural Gas Data and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations contained herein.

ITEM 3. LEGAL PROCEEDINGS

In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We currently have no legal proceedings with a probable adverse outcome. Therefore, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are listed and traded on the NYSE under the symbol “QRE.” As of the close of business on March 2, 2014, based upon information received from our transfer agent and brokers and nominees, we had 156 common unitholders of record. This number does not include owners for whom common units may be held in “street name.” The table below represents the daily high and low sales prices per common unit for the quarters indicated.



	Common Unit Price Range
2013	High		Low
October 1 - December 31	$	18.24	$	16.10
July 1 - September 30	$	17.95	$	14.76
April 1 - June 30	$	18.46	$	15.77
January 1 - March 31	$	18.69	$	16.25
2012
October 1 - December 31	$	20.99	$	15.56
July 1 - September 30	$	19.78	$	16.05
April 1 - June 30	$	22.38	$	15.25
January 1 - March 31	$	23.88	$	20.24

We have also issued 16,666,667 preferred units and 6,133,558 Class B units for which there is no established public trading market. The preferred units are held by the Fund and, subsequent to the GP Buyout Transaction, the Class B units are held by the former owners of our general partner.

Unitholder Return Performance Presentation

The performance graph below compared the total unitholder return on the Partnership’s units, with the total return on the Standard & Poor’s 500 Index (the “S&P 500”) and the Alerian MLP Index, a weighted composite of 50 prominent energy master limited partnerships. Total return includes the changes in market price, adjusted for reinvested dividends or distributions, for the period shown on the performance graph and assumes that $100 was invested in the Partnership, S&P 500, and the Alerian MLP Index on December 31, 2010. The results shown in the graph below are not necessarily indicative of future performance.


	December 31,
	2013	2012	2011	2010
QR Energy, LP	113	98	107	100
Alerian MLP Index	151	119	114	100
S&P 500 Index	156	118	102	100

Notwithstanding anything to the contrary set forth in any of the Partnership’s previous or future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934 that might incorporate this Annual Report on Form 10-K or future filings with the SEC, in whole or in part, the preceding performance information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or incorporated by reference into any filing except to the extent this performance presentation is specifically incorporated by reference therein.

Class B Units

On February 22, 2013, our general partner elected to convert 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 were issued and outstanding upon conversion. Our general partner received a reduced fourth quarter management incentive fee of $0.7 million and received a distribution of $3.0 million on the Class B units related to the fourth quarter 2012.

In connection with the GP Buyout Transaction, these Class B units were distributed to the former owners of our general partner. Additionally, 51,036 general partner units were converted into Class B units and distributed to the former owners of our general partner.

Class C Preferred Units

In connection with the acquisition of the October 2011 Transferred Properties, we issued to the Fund 16,666,667 Class C Convertible Preferred Units. The preferred units receive a preferred quarterly distribution of $0.21 per preferred unit equal to a 4.0% annual coupon on the par value of $21.00, for the first three years following the date of issuance. Beginning on January 1, 2015, distributions on Preferred Units will be the greater of $0.475 per unit or the distribution payable on Common Units with respect to such quarter. The Preferred Units are only redeemable for cash in a complete liquidation. The Preferred Units are convertible into common units under specific circumstances at the option of either the holder or the Partnership into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment. The Preferred Units have the same voting rights as common units.

Cash Distribution Policy

Our partnership agreement, as amended, requires that within 45 days after the end of each quarter, or at our general partner’s sole discretion, in three equal installments within 15, 45, and 75 days following the end of each quarter, we distribute all of our available cash to preferred unitholders, in arrears, and common unitholders and Class B unitholders of record on the applicable record date, as determined by QRE GP.

Available cash, for any quarter prior to liquidation, consists of all cash on hand at the end of the quarter:

less the amount of cash reserves established by QRE GP to:

(i.)

provide for the proper conduct of our business;

(ii.)

comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation; and

(iii.)

provide funds for distribution to our unitholders and to QRE GP for any one or more of the next four quarters.

less, the aggregate Preferred Unit distribution accrued and payable for the quarter;

plus, if QRE GP so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter.

Effective December 22, 2012 the subordinated period ended. As a result, each outstanding subordinated unit converted into one common unit. We distribute available cash to the general partner and all unitholders (other than holders of preferred units) pro rata.

Commencing with respect to the fourth quarter of 2013, we distribute available cash to common unitholders on a monthly basis. We intend to continue to make regular cash distributions to unitholders on a monthly or quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit facility prohibits us from making cash distributions if any potential default or event of default, as defined in our credit facility, occurs or would result from the cash distribution.

Cash Distributions to Unitholders


										Limited Partners
												Affiliated
For the period ended		Distributions to Preferred Unitholders		Distributions per Preferred Unit(1)		General Partner		Class B		Public Common		Common		Subordinated		Total Distributions to Other Unitholders		Distributions per other units

December 31, 2011 (2)	$	3,424	$	0.21	$	16	$		$	8,344	$	5,368	$	3,393	$	17,121	$	0.4750
March 31, 2012 (2)		3,500		0.21		20				17,892		-		3,394		21,306		0.4750
June 30, 2012 (2)		3,500		0.21		20				18,584		-		3,484		22,088		0.4875
September 30, 2012 (2)		3,500		0.21		20				18,529		-		3,484		22,033		0.4875
December 31, 2012 (2)		3,500		0.21		25				25,275		3,484		-		28,784		0.4875
December 31, 2012 (3)		-		-		-		2,990		-		-		-		2,990		0.4875
March 31, 2013 (2)		3,500		0.21		25		2,990		25,480		3,484		-		31,979		0.4875
June 30, 2013 (2)		3,500		0.21		25		2,990		25,475		3,484		-		31,974		0.4875
September 30, 2013 (2)		3,500		0.21		25		2,881		25,465		3,484		-		31,855		0.4875
December 31, 2013 (2)		3,500		0.21		-		-		-		-		-		-		-
December 31, 2013 (4)		-		-		8		987		8,489		1,161		-		10,645		0.1625
December 31, 2013 (5)		-		-		8		997		8,489		1,161		-		10,655		0.1625
December 31, 2013 (6)						8		997		8,489		1,161		-		10,655		0.1625

⁽¹⁾

Preferred Units were prorated a quarterly distribution for the portion of the fourth quarter beginning on October 3, 2011 through December 31, 2011 in accordance with the Partnership Agreement.

⁽²⁾

Distributions were made within 45 days after the end of each quarter.

⁽³⁾

The December 31, 2012 and March 31, 2013 distributions to the Class B units were paid 45 days after the end of the first quarter 2013.

⁽⁴⁾

In December 2013, the Board of Directors approved the first monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in January 2014 to the unitholders of record as of January 13, 2014. This distribution was recorded in the fourth quarter 2013.

⁽⁵⁾

In January 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in February 2014 to the unitholders of record as of February 10, 2014. For more information see Part II, Item 8. Financial Statements and Supplementary Data – Note 22 – Subsequent Events for further details.

⁽⁶⁾

In February 2014, the Board of Directors approved the third monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which will be paid in March 2014 to the unitholders of record as of March 10, 2014. For more information see Note 22 – Subsequent Events for further details.

Common Unit Distributions. In February 2014, the Board of Director’s approved the third monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which will be paid in March 2014 to the unitholders of record as of March 10, 2014. The third monthly distribution, with the first and second monthly distributions, will aggregate to a total distribution of $0.4875 per unit with respect to the fourth quarter 2013.

Preferred Unit Distribution. For the period beginning on October 3, 2011 and ending on December 31, 2014, we will distribute $0.21 per preferred unit on a quarterly basis. As of December 31, 2013 we had accrued a fourth quarter distribution payable of $3.5 million to preferred unitholders which was paid in February 2014.

Class B Unit Distribution. Class B unitholders are entitled to distributions as if they were outstanding on the first day of any quarter. As a result of the general partner’s conversion election, the general partner received a distribution of $3.0 million on its Class B units related to the fourth quarter of 2012.

We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution.

Management Incentive Fee

During 2013, for each quarter for which we paid cash distributions that equaled or exceeded the Target Distribution, our general partner was entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of our management incentive fee base, which was equal to the sum of:

the future net revenue of our estimated proved oil and natural gas reserves, discounted to present value at 10% per annum and calculated based on SEC methodology, adjusted for our commodity derivative contracts; and

the fair market value of our assets, other than our estimated oil and natural gas reserves and our commodity derivative contracts, that principally produce qualifying income for federal income tax purposes, at such value as may be determined by the board of directors of our general partner and approved by the conflicts committee of our general partner’s board of directors.

This management incentive fee base was calculated as of December 31 (with respect to the first and second calendar quarters and based on a fully engineered reserve report) or June 30 (with respect to the third and fourth calendar quarters and based on an internally engineered reserve report), immediately preceding the quarter in respect of which payment of a management incentive fee is due.

Deferred Class B Unit Issuances

The former owners of the general partner are entitled to receive an annual installment of Class B units with respect to any calendar year in which we pay a distribution of $0.4744 per unit with respect to each quarter, achieved a Distribution Coverage Ratio (as defined in our Partnership Agreement) for the year of at least 1.0 and achieve a Total Debt to EBITDAX (as defined in our Partnership Agreement) of no greater than 4.0 for each quarter during such year, unless any excess has been approved by the conflicts committee of our general partner

Securities Authorized for Issuance under Equity Compensation Plans

See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding our equity compensation plans as of December 31, 2013.

Unregistered Sales of Equity Securities

None. For a description of unregistered equity securities that will be and may continue to be issued to our general partner in the future, please see “Deferred Class B Unit Issuances” above.

Issuer Purchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA

The selected consolidated financial data presented as of and for the years ended December 31, 2013, 2012 and 2011, and for the period from December 22, 2010 to December 31, 2010 is derived from our audited financial statements. The selected financial data for the period from January 1, 2010 to December 21, 2010 and as of and for the year ended December 2009 is derived from the audited financial statements of our Predecessor. The selected financial data should be read in conjunction with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8. Financial Statements and Supplementary Data, both contained herein. The following table shows selected financial data of the Partnership and the Predecessor for the periods and as of the dates indicated.


		Partnership							Predecessor
		Year Ended		Year Ended		Year Ended		December 22 to		January 1 to		Year Ended
		December 31,		December 31,		December 31,		December 31,		December 21,		December 31,
In thousands, except per unit amounts		2013		2012		2011		2010		2010		2009
Statement of Operations Data:
Revenues:
Oil and natural gas sales	$	446,801	$	368,189	$	356,579	$	8,927	$	244,572	$	69,823
Disposal, processing and other		8,828		3,809		4,325		59		8,814		2,978
Total Revenues		455,629		371,998		360,904		8,986		253,386		72,801
Operating costs and expenses:
Disposal and related expenses		6,597		-		-		-		-		-
Production expense		174,101		143,938		132,227		3,498		108,408		44,841
Impairment of oil and natural gas properties		-		-		-		-		-		28,338
Depreciation, depletion and amortization		115,184		105,796		94,993		2,588		66,482		16,993
Accretion of asset retirement obligations		7,456		5,648		4,593		130		3,674		3,585
Management fees (1)		-		-		-		-		10,486		12,018
General and administrative and other		41,901		42,275		37,315		925		25,701		19,279
Acquisition and transaction costs		1,487		4,000		-		-		6,340		-
Bargain purchase gain		-		-		-		-		-		(1,200)
Total operating costs and expenses		346,726		301,657		269,128		7,141		221,091		123,854
Income (loss) from operations		108,903		70,341		91,776		1,845		32,295		(51,053)
Other income (expense):
Gain (loss) on commodity derivative contracts, net		(1,217)		53,071		47,860		(12,682)		13,577		(63,120)
Gain on equity share issuance		-		-		-		-		4,064		-
Interest expense, net		(48,000)		(43,133)		(50,491)		(1,266)		(22,179)		(3,716)
Other income		1,589		-		-		-		4,264		2,657
Total other income (expense)		(47,628)		9,938		(2,631)		(13,948)		(274)		(64,179)
Income (loss) before income taxes		61,275		80,279		89,145		(12,103)		32,021		(115,232)
Income tax benefit (expense), net		353		(528)		(850)		66		(108)		(182)
Net income (loss)	$	61,628	$	79,751	$	88,295	$	(12,037)	$	31,913	$	(115,414)
Less: Net income (loss) attributable to noncontrolling interest		663		-		-		-
Net income (loss) attributable to QR Energy, LP		60,965		79,751		88,295		(12,037)
Net income (loss) attributable to QR Energy, LP per limited partner unit:
Common unitholders' (basic)	$	0.26	$	0.19	$	0.10	$	(0.21)
Common unitholders' (dilutive)		0.26		0.19		0.10		(0.21)
Subordinated unitholders' (basic and dilutive)		-		0.11		0.10		(0.21)
Weighted average number of limited partner units outstanding:
Common (basic)		58,524		35,132		28,728		26,298
Common (diluted)		58,524		35,282		28,728		26,298
Subordinated units (basic and diluted)		-		6,970		7,146		7,146
Other Financial Data:
Adjusted EBITDA (2)	$	265,323	$	272,099	$	237,175	$	5,144	$	116,152	$	48,513
Distributable cash flow (3)		131,935		152,476		148,714		3,314
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	202,145	$	227,150	$	112,557	$	2,808	$	95,945	$	64,907
Investing activities		(218,195)		(592,279)		(72,143)		(78,670)		(956,877)		(55,458)
Financing activities		(2,426)		379,532		(25,176)		78,057		903,448		(13,328)
Balance Sheet Data:
Working capital	$	9,473	$	65,625	$	26,418	$	(6,421)		(4)		(74)
Total assets		1,815,927		1,686,527		1,154,344		1,033,848		(4)		226,770
Total debt		911,593		766,076		615,000		567,000		(4)		86,450
Non-controlling interests		8,549		-		-		-		(4)		14,733
Total Partners' capital		637,459		714,564		362,698		326,694		(4)		(1,421)

⁽¹⁾

Represents fees paid by the Fund to its general partner for the provision of certain administrative and acquisition services during the period from January 1, 2010 to December 21, 2010 and the year ended December 31, 2009.

⁽²⁾

Adjusted EBITDA is a Non-GAAP financial measure. See the reconciliation to its most comparable GAAP measure directly below.

⁽³⁾

Distributable Cash Flow is a Non-GAAP financial measure. See the reconciliation to its most comparable GAAP measure directly below.

⁽⁴⁾

These balance sheet amounts are not presented as they are as of December 21, 2010 and therefore are not included in the Predecessor’s financial statements included in Part II, Item 8. Financial Statements and Supplementary Data.

Non-GAAP Financial Measures

We include in this report the non-GAAP financial measures Adjusted EBITDA and Distributable Cash Flow and provide our calculations of Adjusted EBITDA and Distributable Cash Flow and reconciliations to their most directly comparable financial measures calculated and presented in accordance with GAAP. In the second quarter 2012, we revised our calculation of Adjusted EBITDA from prior periods, as discussed below.

Adjusted EBITDA

We define Adjusted EBITDA as net income from which we add or subtract the following:

Net interest expense, including gains and losses on interest rate derivative contracts;

Depreciation, depletion, and amortization;

Accretion of asset retirement obligations;

Gains or losses due to effects of change in prices on natural gas imbalances;

Gains or losses on commodity derivative contracts, net;

Cash received or paid on the settlement of commodity derivative contracts, net

Income tax expense or benefit;

Other income or expense;

Interest income

Impairments;

Non-cash general and administrative expenses, and acquisition and transaction costs;

Pension and postretirement expense or credit; and

Beginning with third quarter 2013, noncontrolling interest amounts attributable to each of the items above, as applicable, which revert the calculation back to the Adjusted EBITDA attributable to the Partnership.

In 2012 and 2011, we used Adjusted EBITDA, as defined under the Services Agreement, to calculate the quarterly administrative services fee our general partner paid to QRM under the Services Agreement between our general partner and QRM. See Part I, Item 1. Business – Operations – Administrative Services Fee.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

the cash flow generated by our assets, without regard to financing methods, capital structure or historical cost basis; and

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness.

In addition, management uses Adjusted EBITDA to evaluate cash available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.

The following table presents our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and cash flows provided by operating activities, our most directly comparable GAAP financial measures, for each of the periods indicated.


		Year Ended		Year Ended		Year Ended
		December 31,		December 31,		December 31,
Thousands of Dollars		2013		2012		2011
Reconciliation of Net
Income to Adjusted EBITDA:
Net income (loss)	$	61,628	$	79,751	$	88,295
Loss (gain) on commodity derivative contracts, net (1)		1,217		(53,071)		(47,860)
Cash received (paid) to settle commodity derivative contracts, net (2)		24,920		49,800		(72,053)
Loss on modification of derivative contracts		-		-		83,399
Loss (gain) on effect of change in prices on gas imbalances		862		1,341		(1,446)
Depletion, depreciation and amortization		115,184		105,796		94,993
Accretion of asset retirement obligations		7,456		5,648		4,593
Interest expense, net		48,000		43,133		50,491
Other (income)/expense		(1,589)		-		-
Income tax expense (benefit)		(353)		528		850
Noncash general and administrative expenses and
acquisition and transaction costs		8,367		39,173		35,913
Noncontrolling interest		(369)		-		-
Adjusted EBITDA	$	265,323	$	272,099	$	237,175

Reconciliation of Net Cash from Operating
Activities to Adjusted EBITDA:
Net cash provided by operating activities	$	202,145	$	227,150	$	112,557
(Increase) decrease in working capital		18,349		(4,269)		19,347
Loss (gain) on effect of change in prices on gas imbalances		862		1,341		(1,446)
Timing differences related to general and administrative allocation		-		(2,155)		(159)
Acquisitions costs		1,487		-		-
Loss on modification of derivative contracts / other		-		-		83,399
Other (income)		(270)		-		-
Net income attributable to noncontrolling interests		(369)		-		-
Interest expense (3)		46,905		51,735		23,537
Other amortization		(3,737)		(1,859)		(61)
Income tax expense (benefit), current		(49)		156		1
Adjusted EBITDA	$	265,323	$	272,099	$	237,175

⁽¹⁾

Represents total derivative loss (gain) reported on our consolidated statements of operations.

⁽²⁾

Represents the net cash received (paid) on commodity derivative contracts that were settled during the respective periods and does not include any cost recovery.

⁽³⁾

Interest expense adjusted for noncash items comprised of amortization of deferred financing costs and gains (losses) on interest rate derivative instruments.

The decrease in Adjusted EBITDA of $6.8 million to $265.3 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012 is mainly attributable to an increase in allocated G&A expense being reimbursed by us to QRM, partially offset by higher cash operating margins. The increase in Adjusted EBITDA of $34.9 million to $272.1 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011 is mainly attributable to higher cash operating margins, partially offset by higher G&A administrative fees paid to QRM.

Distributable Cash Flow

We define Distributable Cash Flow as Adjusted EBITDA less cash interest expense, estimated maintenance capital expenditures, distributions to preferred unitholders, and the management incentive fee applicable to the period. Estimated maintenance capital expenditures are calculated based on our estimate of the capital required to maintain our current production for five years, on average. This estimate is made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business.

Distributable Cash Flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserve by our general partner) to the cash distributions we expect to pay our unitholders. Distributable Cash Flow is also an important financial measure for our unitholders as it serves as an indicator of our success in providing a cash return on investment. Specifically, distributable cash flow indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable Cash Flow is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the yield is based on the amount of cash distributions the entity pays to a unitholder compared to the unit price.

Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate Distributable Cash Flow in the same manner. The table below summarizes our distributable cash flow for each of the periods indicated.


		Year Ended		Year Ended		Year Ended
		December 31,		December 31,		December 31,
		2013		2012		2011
Adjusted EBITDA	$	265,323	$	272,099	$	237,175
Maintenance capital expenditures		(68,834)		(62,750)		(61,000)
Cash interest expense		(46,504)		(36,004)		(22,465)
Distributions to preferred unitholders		(14,000)		(14,000)		(3,424)
Management incentive fee earned (1)		(4,050)		(6,869)		(1,572)
Distributable cash flow	$	131,935	$	152,476	$	148,714

⁽¹⁾

The management incentive fee is not recognized until the corresponding quarter’s common unit distribution is declared. The 2013 fourth quarter’s common unit distribution was not declared, and therefore the management incentive fee was not recognized, until the first quarter of 2014. Therefore, the management incentive fee earned for the full year 2013 includes $1.3 million earned with respect to, but not recognized in, the fourth quarter 2013.

The decrease in Distributable Cash Flow of $20.5 million to $131.9 million for the year ended December 31, 2013 compared to the year ended December 31, 2012 is mainly attributable to the decrease in Adjusted EBITDA, an increase in maintenance capital expenditures, and an increase in cash interest expense due to additional borrowings, partially offset by lower management incentive fee earned by QRE GP. The increase in Distributable Cash Flow of $3.8 million to $152.5 million for the year ended December 31, 2012 compared to the year ended December 31, 2011 is mainly attributable to the increase in Adjusted EBITDA partially offset by the full year effect of distributions to preferred unitholders and the management incentive fee earned by QRE GP that were not present during the year ended December 31, 2011 and interest on the Senior Notes issued in July 2012.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes Part II, Item 8. Financial Statements and Supplementary Data contained herein. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Part I, Item 1A. of this Form 10-K. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Information” in the front of this Form 10-K.

Overview

We are a Delaware limited partnership formed in September 2010 by affiliates of the Fund to own and acquire producing oil and natural gas properties in North America.

Our properties are located in Alabama, Arkansas, Florida, Kansas, Louisiana, Michigan, New Mexico, Oklahoma and Texas. As of December 31, 2013, we had estimated net proved reserves of 73.0 MMBbl of oil and condensate, 151.7 Bcf of natural gas and 10.8 MMBbl of NGLs, or 109.1 MMBoe and a standardized measure of $2.0 billion.

GP Buyout Transaction

Acquisitions and Conveyances

On August 6, 2013, we closed the acquisition of primarily oil properties located in East Texas (the “2013 East Texas Acquisition”) from a private seller for $107.8 million in cash subject to customary purchase price adjustments. The acquired properties (the “2013 East Texas Properties”) had estimated proved reserves of 5.9 MMBoe as of the acquisition date utilizing SEC case pricing. The acquisition had an effective date of June 1, 2013. In addition, the 2013 East Texas Acquisition included an interest in a saltwater disposal company, ETSWDC, that resulted in us owning a controlling interest. See Part II, Item 8. Financial Statements and Supplementary Data – Note 4 – Acquisitions for further details.

On December 28, 2012, we completed the acquisition of the December 2012 Transferred Properties consisting of certain oil and natural gas properties from the Fund, pursuant to a purchase and sale agreement for $28.6 million in cash, after customary purchase price adjustments, and the assumption of $115 million in debt. The December 2012 Transferred Properties consisted of working interests in 50 gross (46 net) producing wells, of which we owned an approximate 92.46% average working interest.

On December 4, 2012, we closed the acquisition of primarily oil properties located in East Texas (the “2012 East Texas Properties”) from a private seller for $214.3 million in cash, after customary purchase price adjustments (the “2012 East Texas Acquisition”). The acquisition had an effective date of November 1, 2012. During the first

quarter 2013, we received the $2.3 million receivable from the seller that was recorded as a purchase price adjustment at the date of the sale.

On April 20, 2012, we closed the acquisition of primarily oil properties, almost all of which are located in the Ark-La-Tex area, 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 acquisition had an effective date of January 1, 2012.

On October 3, 2011, we completed the acquisition of the October 2011 Transferred Properties located in the Permian Basin, Ark-La-Tex, and MidContinent areas from the Fund pursuant to a purchase and sale agreement (the “October 2011 Purchase Agreement”) having an effective date of October 1, 2011 in exchange for 16,666,667 Class C Convertible Preferred Units and the assumption of $227 million in debt. The October 2011 Transferred Properties consisted of working interests in 1,669 gross (1,026 net) producing wells, of which we owned an approximate 61.46% average working interest.

Business Environment and Operational Focus

Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and, over time, to increase our quarterly cash distributions.

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

Production volumes;

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

Production expenses and general and administrative expenses; and

Adjusted EBITDA and Distributable Cash Flow, each of which is a non-GAAP financial measure.

Production Volumes

Production volumes directly impact our results of operations. For more information about our production volumes and our Predecessor’s production volumes, see “Results of Operations” below.

Realized Prices on the Sale of Oil and Natural Gas

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

Oil Prices. The actual prices realized from the sale of oil differ from the quoted market prices as a result of quality differentials (primarily based on API gravity and sulfur content) and location differentials (primarily based on transportation costs due to the produced oil’s proximity to major consuming and refining markets). In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value, and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur content oil (“sour” oil).

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

Natural Gas Prices. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality differentials (primarily based on Btu, CO₂ and other content by volume) and location differentials (primarily based on transportation costs due to the produced natural gas’ proximity to major consuming markets). Wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO₂ content sells at a premium to natural gas with high sulfur and CO₂ content because of the added cost to separate the sulfur and CO₂ from the natural gas to render it marketable.

The majority of our properties produce wet gas. Our wellhead Btu has an average energy content greater than 1100 Btu and minimal sulfur and CO₂ content and generally receives a premium valuation.

Price Volatility. Historically, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2013, the NYMEX-WTI oil price ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $4.52 per MMBtu to a low of $3.08 per MMBtu. For the five years ended December 31, 2013, the NYMEX-WTI oil price ranged from a high of $113.39 per Bbl to a low of $34.03 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $7.51 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.

Commodity Derivative Contracts. Our hedging policy is intended to reduce the impact to our cash flows from commodity price volatility. 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 the next three-to-five year period.

Production Expenses

We strive to increase our production levels to maximize our revenue and cash available for distribution. Production expenses are the costs incurred in the operation of producing properties. Expenses for well servicing, utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our production expenses. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. We monitor our operations to ensure that we are incurring operating costs at the optimal level. We typically evaluate our oil and natural gas operating costs on a per Boe basis. This unit rate allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers.

General and Administrative Expenses

We share general and administrative expenses with other affiliates who also receive management and accounting services from QRM under a Services Agreement, as defined in Part II, Item 8. Financial Statements and Supplementary Data – Note 19 – Related Party Transactions.

Through 2012, our general and administrative expenses, for any quarter therein, were comprised of:

Direct general and administrative expenses incurred by QRM on our behalf (“Direct G&A”) and charged to us;

Administrative service fees, as discussed in Part II, Item 8. Financial Statements and Supplementary Data –Note 19 – Related Party Transactions, payable by us to QRM during the term of the Services Agreement; and

Our share of allocable indirect general and administrative expenses incurred by QRM on behalf of the affiliates for which it provides management services which are in excess of the administrative services fee charged to us (“Allocated G&A”).

on relative production volumes, has been reviewed and approved by QRE GP’s board of directors, including independent directors, as a reasonable method of sharing these expenses with the Fund and provides for a reasonably accurate depiction of what our general and administrative expenses would be on a stand-alone basis without affiliations with the Fund or QRM.

After December 31, 2012, we are required to reimburse QRM for its share of allocable general and administrative expenses based on the estimated use of such services. We reimburse QRM for general and administrative expenses allocated to us based on the estimated use of such services between us and the Fund. The fee includes Direct G&A plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If our sponsor raises additional funds in the future, the quarterly administrative services costs will be further divided to include the sponsor’s additional funds as well. QRM has discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement. Management believes this allocation methodology is a reasonable method of allocating general and administrative expenses between us and the Fund and provides for a reasonably accurate depiction of what our general and administrative expenses would be on a stand-alone basis without affiliations with the Fund or QRM.

For a detailed description of the administrative services fee paid to Quantum Resources Management pursuant to the Services Agreement, please read Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence – Contracts with the Fund and Its Affiliates – Services Agreement.

Adjusted EBITDA

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

the cash flow generated by our assets, without regard to financing methods, capital structure or historical cost basis; and

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness.

Management also uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to unitholders, develop existing reserves or acquire additional oil and natural gas properties. Previously, we also used Adjusted EBITDA to calculate the administrative services fee our general partner paid to Quantum Resources Management under the Services Agreement. For our definition of Adjusted EBITDA see Part II, Item 6. Selected Financial Data – Non-GAAP Financial Measures. For more information regarding the Services Agreement, see Part III, Item 13. Certain Relationships and Related Transactions and Director Independence – Contracts with The Fund and its Affiliates – Services Agreement.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. For further discussion and a reconciliation of Adjusted EBITDA to net income and cash flows provided by operating activities, see Part II, Item 6. Selected Financial Data – Non-GAAP Financial Measures.

Distributable Cash Flow

Distributable Cash Flow should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Distributable Cash Flow may not be comparable to similarly titled measures of another company

because all companies may not calculate Distributable Cash Flow in the same manner. For further discussion, see Part II, Item 6. Selected Financial Data – Non-GAAP Financials Measures.

Outlook

Consistent with our long-term business strategy, we plan to maintain our focus on adding reserves through acquisitions and exploitation projects and improving the economics of producing oil and natural gas from our existing fields in 2014. We expect these acquisition opportunities may come from the Fund, Quantum Energy Partners and their respective affiliates as well as from unrelated third parties. Our ability to add estimated reserves through acquisitions and exploitation projects is dependent on many factors, including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

In 2014, our capital spending program is expected to be approximately $101.6 million, excluding acquisitions. We anticipate spending approximately 59% in the Ark-La-Tex and Gulf Coast areas primarily on recompletions and workovers, plant upgrades and new well drilling, and 41% in the Permian Basin and MidContinent areas primarily on recompletions and new well drilling.

Critical Accounting Policies and Estimates

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

it requires assumptions to be made that were uncertain at the time the estimate was made, and

changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.

What follows is a discussion of the more significant accounting policies, estimates and judgments. See Part II, Item 8. Financial Statements and Supplementary Data – Note 2 – Summary of Significant Accounting Policies for a discussion of additional accounting policies and estimates made by management.

Business Combinations

We account for all business combinations using the purchase method, in accordance with GAAP. Under the purchase method of accounting, the purchase price is based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets acquired and liabilities assumed are measured at their fair values. The difference between the fair value of assets acquired and liabilities assumed and the purchase price of the entity, if any, is recorded as either goodwill or a bargain purchase gain. The Partnership has not recognized any goodwill from business combinations.

Transactions Between Entities Under Common Control

From time to time we enter into transactions whereby we receive a transfer of certain oil and natural gas assets from our Predecessor with units issued or cash paid by us. We account for the net assets received using the historical book value of the Predecessor as these are transactions between entities under common control. Our

historical financial statements have been revised to include the results attributable to the assets contributed from the Predecessor as if we owned such assets for all periods presented by the Partnership.

Proved Oil and Natural Gas Reserve Quantities

Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion, and amortization (“DD&A”) expense and the full cost ceiling limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. Netherland, Sewell & Associates, Inc., our independent reserve engineering firm, prepares a reserve report as of December 31 of each year, and we prepare internal estimates of our proved reserves as of June 30 of each year. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines and Netherland, Sewell & Associates, Inc. adheres to the same guidelines when preparing their reserve reports. Assumptions used by independent reserve engineers in calculating reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. The accuracy of reserve estimates is a function of the:

quality and quantity of available data;

interpretation of that data;

accuracy of various mandated economic assumptions; and

judgment of the independent reserve engineer.

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

Netherland, Sewell & Associates, Inc., prepares a fully-engineered reserve and economic evaluation of all our properties on a lease, unit or well-by-well basis, depending on the availability of well-level production data. The data for a given reservoir may change substantially over time as a result of numerous factors including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves. The estimate of proved oil and natural gas reserves primarily impacts property, plant and equipment amounts in the consolidated balance sheet and the DD&A amounts in the consolidated statement of operations.

Downward revisions have the effect of increasing our DD&A rate, while upward revisions have the effect of decreasing our DD&A rate. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of DD&A expense in a given period decreases and vice versa.

Market prices have been volatile and a decline of proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. Declines in future oil and natural gas market prices could have a negative impact on our reserve value and could result in an impairment of our oil and gas properties. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of oil and gas producing properties for impairment. For example, a hypothetical 10% decrease in the 12 month average of oil prices would decrease the standardized measure of our estimated proved reserves as of December 31, 2013 by $301 million, and a hypothetical 10% decrease in the 12 month average of natural gas prices would decrease the standardized measure of our estimated reserves as of December 31, 2013 by $24 million. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Unevaluated Properties

We have acquired unevaluated properties which are not being depleted pending determination of the existence of proved reserves. Unevaluated properties are assessed periodically to ascertain whether there is a probability of obtaining proved reserves in the future. When it is determined that these properties have been promoted to a proved reserve category or there is no longer any probability of obtaining proved reserves from the properties, the costs associated with these properties are transferred into the amortization base to be included in the depletion calculation and subject to the ceiling test limitation. Unevaluated properties whose costs are individually significant are assessed individually considering the primary lease terms of the properties, the holding period of the properties, and geographic and geological data obtained related to the properties. Where it is not practical to assess properties individually as their costs are not individually significant, such properties are grouped for purposes of the periodic assessment.

Full Cost Method of Accounting

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

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write down to the extent of such excess. If required, it would reduce earnings and impact partners’ capital in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that write downs of our oil and natural gas properties could occur in the future.

Depreciation, Depletion and Amortization

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of DD&A expense and revisions in such estimates may alter the rate of future depletion expense. Holding all other factors constant, if reserves are revised upward, earnings would increase due to lower depletion expense. Likewise, if reserves are revised downward, earnings would decrease due to higher depletion expense or due to a ceiling test write-down. For example, a 10% negative revision to proved reserves as of December 31, 2013 would increase the DD&A rate by approximately 10.91%. This represents an increase of DD&A expense of $1.92 per Boe, or a change from $17.63 to $19.55 per Boe for the year ended December 31, 2013. This estimated impact is based on current data as of December 31, 2013 and actual events could require different adjustments to DD&A.

Derivative Financial Instruments

We periodically use derivative financial instruments for non-trading purposes to manage and reduce market volatility and other market risks associated with our oil and natural gas production and interest rates on our revolving credit facility. These arrangements are structured to reduce our exposure to commodity price decreases and interest rate increases, but they can also limit the benefit we might otherwise receive from commodity price

increases and interest rate decreases. Our hedging activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. We have elected not to apply hedge accounting to our derivatives. Accordingly, we carry our derivatives at fair value on our consolidated balance sheet, with the changes in the fair value included in our consolidated statement of operations in the period in which the change occurs. In determining the amounts to be recorded, we are required to estimate the fair values of the derivatives. Although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have properly presented all asset and liability positions without netting.

The primary assumptions used to estimate the fair value of derivative instruments is pricing. Our pricing assumptions are based upon price curves derived from actual prices observed in the market, pricing information supplied by a third-party valuation specialist and independent pricing sources and models that rely on this forward pricing information. The extent to which we rely on pricing information received from third parties in developing these assumptions is based, in part, on whether the information considers the availability of observable data in the marketplace. For example, in relatively illiquid markets we may make adjustments to the pricing information we receive from third parties based on our evaluation of whether third-party market participants would use pricing assumptions consistent with these sources.

As of December 31, 2013, we had the following derivative instruments outstanding:


Commodity	Index	2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		6,715		7,356		6,293		5,547
Average price ($/Bbls)		$	95.30	$	93.74	$	90.03	$	86.23
Hedged Volume (Bbls/d)	LLS		3,000		-		-		-
Average price ($/Bbls)		$	99.62		-		-		-
Basis
Hedged Volume (Bbls/d)	WTS/WTI		2,400		-		-		-
Average price ($/Bbls)		$	(2.10)		-		-		-
Collars
Hedged Volume (Bbls/d)	WTI		425		1,025		1,500		-
Average floor price ($/Bbls)		$	90.00	$	90.00	$	80.00		-
Average ceiling price ($/Bbls)		$	106.50	$	110.00	$	102.00		-

Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		26,622		7,191		11,350		10,445
Average price ($/MMBtu)		$	6.18	$	5.34	$	4.27	$	4.47
Basis Swaps (1)
Hedged Volume (MMBtu/d)	Henry Hub		17,066		14,400		-		-
Average price ($/MMBtu)		$	(0.19)	$	(0.19)		-		-
Collars
Hedged Volume (MMBtu/d)	Henry Hub		4,966		18,000		630		595
Average floor price ($/MMBtu)		$	5.74	$	5.00	$	4.00	$	4.00
Average ceiling price ($/MMBtu)		$	7.51	$	7.48	$	5.55	$	6.15
Puts
Hedged Volume (MMBtu/d)	Henry Hub		-		420		11,350		10,445
Average price ($/MMBtu)			-	$	4.00	$	4.00	$	4.00

⁽¹⁾

Our natural gas basis swaps are used to hedge the differential between Henry Hub and various points.

Asset Retirement Obligation

The initial estimated retirement obligation associated with oil and natural gas properties is recognized as a liability, with a corresponding increase in the carrying value of oil and natural gas properties. Amortization expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset

retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations. Upon settlement of liabilities related to our other property, plant and equipment, we record a gain or loss in earnings to the extent the actual costs differ from the recorded liability.

Revenue Recognition and Natural Gas Balancing

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

Unit Based Compensation

Our unit based compensation plan includes service and performance restricted units. The compensation expense associated with the performance restricted units is based on a Monte Carlo model which includes various significant assumptions, including the risk-free rate, volatility of returns, correlation in movement of total unitholder return relative to a relevant peer group and the expected distribution rate.

The assumptions used to value our performance restricted units are our best estimate but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used or if actual market results differ from the assumptions, unit-based compensation could be significantly different from our estimates.

Results of Operations

Because affiliates of the Fund own 100% of our general partner and an aggregate 29.2% limited partner interest in us including all of our preferred units as of December 31, 2013, each acquisition of assets from the Predecessor is considered a transfer of net assets between entities under common control. As a result, we are required to revise our financial statements to include the activities of such assets for all periods presented by the Partnership, similar to a pooling of interests, to include the financial position, results of operations, and cash flows of the assets acquired and liabilities assumed. The table set forth below includes the recast historical financial information as if the acquired assets were owned by us for all periods presented for the Partnership.

The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets have been prepared from the Predecessor’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.

The table below summarizes certain of the results of operations and period-to-period comparisons for the periods indicated (in thousands, except operating and per unit amounts).


	Year		Year		Year
	Ended		Ended		Ended
	December 31,		December 31,		December 31,
	2013		2012		2011
Revenues
Oil sales	$	377,246	$	296,684	$	252,744
Natural gas sales		40,134		37,174		65,741
NGLs sales		29,421		34,331		38,094
Disposal, processing and other		8,828		3,809		4,325
Total Revenue		455,629		371,998		360,904
Operating Expenses
Lease operating expenses		141,926		114,231		104,680
Production and other taxes		29,304		25,921		23,472
Processing and transportation		2,871		3,786		4,075
Total production expenses		174,101		143,938		132,227
Disposal and related expenses		6,597		-		-
Depreciation, depletion and amortization		115,184		105,796		94,993
Accretion of asset retirement obligations		7,456		5,648		4,593
General and administrative		41,901		42,275		37,315
Acquisition and transaction costs		1,487		4,000		-
Total operating expenses		346,726		301,657		269,128
Operating income		108,903		70,341		91,776
Other income (expense):
Gain (loss) on commodity derivative contracts, net		(1,217)		53,071		47,860
Interest expense, net		(48,000)		(43,133)		(50,491)
Other income (expense)		1,589		-		-
Total other income (expense), net		(47,628)		9,938		(2,631)
Income (loss) before income taxes		61,275		80,279		89,145
Income tax benefit (expense), net		353		(528)		(850)
Net income (loss)		61,628		79,751		88,295
Less: Net income (loss) attributable to noncontrolling interest		663		-		-
Net income (loss) attributable to QR Energy, LP	$	60,965	$	79,751	$	88,295
Sales volumes:
Oil (MBbls)		3,823		3,106		2,594
Natural gas (MMcf)		11,497		13,475		15,106
Natural gas liquids (MBbls)		796		743		680
Total (MBoe)		6,535		6,095		5,792
Average Net Sales Volumes (Boe/d)		17,904		16,653		15,868
Average sales price per unit (1):
Oil (per Bbl)	$	98.68	$	95.52	$	97.43
Natural gas (per Mcf)	$	3.49	$	2.76	$	4.35
Natural gas liquids (per Bbl)	$	36.96	$	46.21	$	56.02
Average unit cost per Boe:
Lease operating expense	$	21.72	$	18.74	$	18.07
Production and other taxes	$	4.48	$	4.25	$	4.05
Depreciation, depletion and amortization	$	17.63	$	17.36	$	16.40
General and administrative expenses	$	6.41	$	6.94	$	6.44

⁽¹⁾

Does not include impact of derivative instruments.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

We recorded net income of $61.6 million during the year ended December 31, 2013 compared to net income of $79.8 million during the year ended December 31, 2012. The decrease was primarily driven by a net decrease in gains on our commodity derivative contracts of $54.3 million resulting in a loss of $1.2 million, offset by a net increase in operating income of $38.6 million resulting in operating income of $108.9 million.

Revenues


		Year ended December 31,
					Increase		Percentage
	2013		2012		(Decrease)		Change
Sales volumes:
Oil (MBbls)		3,823		3,106		717		23	%
Natural Gas (MMcf)		11,497		13,475		(1,978)		(15)	%
NGL (MBbls)		796		743		53		7	%.
Total (MBoe)		6,535		6,095		440		7	%

Average sales prices per unit:
Oil (per Bbl)	$	98.68	$	95.52	$	3.16		3	%
Natural Gas (per Mcf)		3.49		2.76		0.73		26	%
NGL (per Bbl)		36.96		46.21		(9.25)		(20)	%
Total (per Boe)	$	68.37	$	60.41	$	7.96		13	%

Revenues:
Oil sales	$	377,246	$	296,684	$	80,562		27	%
Natural Gas sales		40,134		37,174		2,960		8	%
NGL sales		29,421		34,331		(4,910)		(14)	%
Disposal, processing and other		8,828		-		8,828		-	%
Total oil and natural gas revenue	$	455,629	$	368,189	$	87,440		24	%

Total oil and natural gas revenues increased by $78.6 million to $446.8 million due to increased sales volumes and prices. The increase in sales volumes is primarily due to acquisitions in East Texas during the fourth quarter of 2012 and third quarter of 2013 and improved performance at the Jay field following a turnaround to perform routine maintenance during the second quarter of 2013. This increase was partially offset by a decline in gas sales volumes related to natural declines and downtime in certain fields including a pipeline repair in the ArkLaTex region. The increase in overall prices is due to an increase in oil and natural gas prices and the mix of our volumes despite a decline in NGL prices. The increase in disposal, processing and other revenues is mainly attributable to the operations of the ETSWDC, which we included in our results of operations beginning in August 2013 in connection with the 2013 East Texas Acquisition. These revenues are related to income generated from salt water disposal in the East Texas Oil Field.

Production Expenses. Our production expense increased by $30.2 million to $174.1 million mainly due to an increase in lease operating expenses and production and other taxes and attributable to acquisitions in the fourth quarter of 2012 and third quarter of 2013, whose properties carry a higher operating cost per Boe as compared to existing properties. In addition, the increase in lease operating expense is associated with higher volumes for the Jay field and a turnaround for the Jay field in the current period to perform routine maintenance.

Disposal and Related Expenses. The disposal and related expenses of $6.6 million are attributable to the operations of ETSWDC, which we included in our results of operations beginning in August 2013 in connection with the 2013 East Texas Acquisition.

Depreciation, Depletion and Amortization Expenses. Our DD&A expenses increased by $9.4 million to $115.2 million, or $17.63 per Boe due to higher production volumes in 2013 as a result of acquisitions in the fourth quarter of 2012 and third quarter of 2013.

General and Administrative Expenses. Our general and administrative expenses decreased by $0.4 million to $41.9 million, or $6.41 per Boe.

Effects of Commodity Derivative Contracts. Our commodity derivative contracts decreased by $54.3 million to a net loss of $1.2 million in the current year from a net gain of $53.1 million in the prior year. Gains and losses on commodity derivative contracts result from changes in the current and future commodity prices as compared to fixed price of our open commodity contracts.

Interest Expense, net. Net interest expense increased by $4.9 million to $48.0 million mainly due to interest expense attributable to the senior notes that were issued in late July 2012 and a higher average outstanding borrowing under our revolving credit facility, partially offset by a decrease in a bridge loan commitment fee incurred during 2012, a decrease in net interest rate derivative losses, and a write-off of deferred loan costs in the third quarter of 2012.

Other income, net. Other income of $1.6 million is mainly attributable to the gain on our step-up acquisition investment in the ETSWDC in August 2013 in connection with the 2013 East Texas Acquisition.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Revenues

We recorded net income of $79.8 million during the year ended December 31, 2012 compared to net income of $88.3 million during the year ended December 31, 2011. The decrease was primarily driven by a decrease in operating income of $21.4 million to $70.3 million, offset by a net increase in gains on our commodity derivative contracts of $5.3 million and a decrease in interest expense of $7.4 million.

s
		Year ended December 31,
					Increase		Percentage
	2012		2011		(Decrease)		Change
Sales volumes:
Oil (MBbls)		3,106		2,594		512		20	%
Natural Gas (MMcf)		13,475		15,106		(1,631)		(11)	%
NGL (MBbls)		743		680		63		9	%.
Total (MBoe)		6,095		5,792		303		5	%

Average sales prices per unit:
Oil (per Bbl)	$	95.52	$	97.43	$	(1.91)		(2)	%
Natural Gas (per Mcf)		2.76		4.35		(1.59)		(37)	%
NGL (per Bbl)		46.21		56.02		(9.81)		(18)	%
Total (per Boe)	$	60.41	$	61.57	$	(1.16)		(2)	%

Revenues:
Oil sales	$	296,684	$	252,744	$	43,940		17	%
Natural Gas sales		37,174		65,741		(28,567)		(43)	%
NGL sales		34,331		38,094		(3,763)		(10)	%
Total oil and gas revenue	$	368,189	$	356,579	$	11,610		3	%

Total oil and natural gas revenues increased by $11.6 million to $368.2 million due to higher volumes despite a decrease in the average sales price in all commodities. The increase in volumes is mainly attributable to increased oil volumes related to the assets acquired in the Prize Acquisition and East Texas Oil Field Acquisition along with increased in the Jay field during the latter part of the year, partially offset by a decrease in natural gas volumes due to ongoing maintenance of wells and the effects of natural declines in the year ended December 31, 2012 as compared to the year ended December 31, 2011.

Production Expenses. Our production expense increased by $11.6 million to $143.9 million mainly due to an increase in lease operating expenses attributable to the Prize Acquisition and the East Texas Oil Field Acquisition completed in 2012.

Depreciation, Depletion and Amortization Expenses. Our DD&A expenses increased by $10.8 million to $105.8 million, or $17.36 per Boe mainly due to increased volumes attributable to the Prize Acquisition completed in 2012.

General and Administrative and Other Expenses. Our general and administrative expenses increased by $5.0 million to $42.3 million, or $6.94 per Boe mainly due to the higher personnel costs associated with increasing our staffing levels to meet our current organizational needs.

Effects of Commodity Derivative Contracts. Our net gain on commodity derivative contracts increased by $5.2 million to $53.1 million. Gains and losses on commodity derivative contracts result from changes in the current and future commodity prices as compared to fixed price of our open commodity contracts.

Interest Expense, net. Net interest expense decreased by $7.4 million to $43.1 million mainly due to a net decrease in losses on interest rate derivative contracts of $19.2 million related a to a smaller decline in interest rates during 2012 versus 2011, partially offset by an increase in interest expense of $9.6 million related to the Senior Notes issued during late July 2012.

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations or to meet our collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for oil and natural gas and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under our credit facility, and debt and equity offerings. The capital markets experience volatility from time to time. Our exposure to credit conditions includes our credit facility, debt securities, cash investments and counterparty performance risks. Volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

We continue to evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions. Should any of these financial counterparties not perform, we may not realize the benefit of some of our derivatives under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our oil, natural gas, and NGLs to a variety of purchasers. Non-performance by a customer could result in losses.

Crude oil and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have hedged the commodity prices associated with a portion of our expected oil and natural gas volumes through 2017 by entering into derivative financial instruments including fixed for floating oil and natural gas swaps. With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. 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 the next 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 derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. The current market conditions may also impact our ability to enter into future commodity derivative contracts. A significant reduction in commodity prices could reduce our operating margins and cash flow from operations.

As of December 31, 2013, our liquidity of $324.9 million consisted of $13.4 million of cash on hand, which includes $2.7 million that is held by a subsidiary which is not wholly-owned, and $311.5 million of availability under our credit facility after giving consideration to $23.5 million of outstanding letters of credit. As of December

31, 2013, we had $615.0 million of borrowings outstanding under our credit facility. As of March 2, 2014, we had $678 million of borrowings outstanding and $23.5 million of letters of credit issued resulting in $248.5 million of borrowing availability under our revolving credit facility.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. We believe our cash flows provided by operating activities will be sufficient to meet our operating requirements for the next twelve months.

As of December 31, 2013, we had a positive working capital balance of $9.5 million.

Credit Facilities

Credit Facility

On December 22, 2010, in connection with our IPO, the Partnership entered into a Credit Agreement along with QRE GP, OLLC as borrower, and a syndicate of banks (the “Credit Agreement”).

As of December 31, 2013, we had a $950 million borrowing base, $615.0 million of borrowings outstanding and $23.5 million of letters of credit issued resulting in $311.5 million of borrowing availability. As of March 2, 2014, we had $678 million of borrowings outstanding and $23.5 million of letters of credit issued resulting in $248.5 million of borrowing availability under our revolving credit facility

Effective January 15, 2013, we entered into the fourth amendment to the Credit Agreement, which increased the borrowing base from $730 million to $900 million and increased the letters of credit commitment from $20 million to $30 million. Effective August 6, 2013, we entered into the fifth amendment to the Credit Agreement, which provides for the exclusion of ETSWDC as a guarantor of our credit facility. On October 15, 2013, our revolving credit facility borrowing base increased to $950 million as a result of our semi-annual borrowing base redetermination. Effective March 2, 2014, we entered into the six amendment to the Credit Agreement, which permits the GP Buyout Transaction.

As of December 31, 2013, the Credit Agreement provides for a five-year, $1.5 billion revolving credit facility maturing on April 20, 2017, with a borrowing base of $950 million. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ pricing assumptions, and other various factors unique to each member bank. The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum. A hypothetical increase of 100 basis points in the underlying interest rate would increase our annual interest expense by $6.2 million based on our outstanding borrowings as of December 31, 2013.

A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we

could be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the Credit Agreement. 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 the Credit Agreement. Our next semi-annual borrowing base redetermination is scheduled for May 2014.

The Credit Agreement requires us to maintain a total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all our assets; make certain investments, acquisitions or certain restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and to provide audited financial statements within 90 days and reviewed quarterly financial statements within 45 days after quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production from total proved reserves for the next two years and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. As of December 31, 2013, we were in compliance with all of the Credit Agreement’s financial covenants.

Senior Notes

On July 30, 2012, we and our wholly-owned subsidiary QRE FC, completed a private placement to eligible purchasers of an aggregate principal amount of $300 million of our 9.25% Senior Notes, due 2020 (the “Senior Notes”). The Senior Notes were issued at 98.62% of par with interest payments to be made February 1 and August 1 each year beginning in 2013. We received approximately $291.2 million of cash proceeds, net of the discount and underwriting fees, with total net proceeds of approximately $290.2 million, after $1.0 million of offering costs. We used the net proceeds from the sale of the Senior Notes to repay borrowings outstanding under our credit facility. In 2012, we filed and completed a registration statement with the SEC to allow holders of the Senior Notes to exchange for registered Senior Notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012 and the exchange offer was completed on November 7, 2012.We have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Our and QRE FC’s obligations under the Senior Notes are guaranteed by OLLC. In the future, the guarantees of OLLC and any future guarantors may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation of such guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor’s debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Part II, Item 8. Financial Statements and Supplementary Data – Note 20 – Subsidiary Guarantors for further details of our guarantors.

The indenture governing the Senior Notes (the “Indenture”) restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale-leaseback transactions; (ii) pay distributions on, or repurchase, equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in

the Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants. The Indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the Senior Notes.

Bridge Loan Commitment

In conjunction with the Prize Acquisition, we entered into a secured commitment (the “Bridge Loan Commitment”) to provide an additional $200 million of bank loans to fund the acquisition as needed. We did not utilize any borrowings under the commitment and, as of May 10, 2012, the Bridge Loan Commitment was terminated by us. We incurred $1.6 million of commitment fees related to the Bridge Loan Commitment which is recorded in interest expense for the year ended December 31, 2012.

Equity Offerings

On January 14, 2014, we filed an automatic registration statement on Form S-3 with the SEC to register our common units, preferred units and our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Part II, Item 8. Financial Statements and Supplementary Data –Note 22 – Subsequent Events for details.

On December 12, 2012, we issued 12,000,000 common units representing limited partnership interests in us to the public pursuant to a registration statement filed with the SEC (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 they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us at $16.24 per unit. Proceeds from the December 2012 Equity Offering, net of transaction costs of $0.2 million and underwriter’s 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.

In connection with the December 2012 Equity Offering, QRE GP purchased 9,289 general partner units in order to maintain its 0.1% ownership percentage in us. The units were purchased at a price of $16.91 per unit for $0.2 million.

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 may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC.

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 to the public pursuant to a registration statement filed with the SEC (the “April 2012 Equity Offering”). In conjunction with the April 2012 Equity Offering, the Partnership granted the underwriters an 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. Proceeds from the April 2012 Equity Offering, net of transaction costs of $0.5 million and underwriters’ discount of $6.8 million, were approximately $162 million.

On April 25, 2012, QRE GP purchased 6,018 general partner units in order to maintain its 0.1% ownership percentage in us. The units were purchased at a price of $19.18 per unit for $0.1 million.

On October 3, 2011, in exchange for the October 2011 Transferred Properties, we issued 16,666,667 Class C Convertible Preferred Units (“Preferred Units”) to the Fund. The fair value of the Preferred Units on October 1, 2011 was $21.27 per unit or $354.5 million with net assets of $252.0 million contributed to the Partnership by the Fund. The value of the Preferred Units in excess of the net assets contributed by the Fund was deemed a $102.5 million distribution from the Partnership as the October 2011 Transferred Properties were accounted for as a transaction between entities under common control and allocated pro rata to the general partner and existing limited partners.

In January 2011, in connection with our initial public offering, the underwriters exercised their over-allotment option in full for 2,250,000 common units issued by the Partnership. Net proceeds from the sale of these common units, after deducting offering costs, were approximately $42 million.

On December 22, 2010, we completed our IPO of 15,000,000 common units representing limited partner interests in us. In connection with the IPO, we issued 11,297,737 common units and 7,145,866 subordinated units in exchange for oil and natural gas assets.

For a description of equity securities that will be and may continue to be issued to the former owners of our general partner in the future, please see Part II, Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities – Deferred Class B Unit Issuances.

Commodity Derivative Contracts

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on the prices of oil and natural gas and our ability to maintain and increase production through acquisitions and exploitation and development projects. Refer to Part II, Item 8. Financial Statements and Supplementary Data – Note 7 – Derivative Activities for further details of our derivative activities.

During the year ended December 31, 2013, we entered into new oil swap contracts and basis swap contracts with settlement dates ranging from 2013 through 2017. All of the new contracts were entered into with counterparties under our revolving credit facility. Additionally, in the fourth quarter of 2013 we converted WTI swaps to LLS swaps.

The following table summarizes our oil and natural gas derivative notional amounts as of December 31, 2013 for the periods indicated through December 31, 2017.


Commodity	Index	2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		6,715		7,356		6,293		5,547
Average price ($/Bbls)		$	95.30	$	93.74	$	90.03	$	86.23
Hedged Volume (Bbls/d)	LLS		3,000		-		-		-
Average price ($/Bbls)		$	99.62		-		-		-
Basis
Hedged Volume (Bbls/d)	WTS/WTI		2,400		-		-		-
Average price ($/Bbls)		$	(2.10)		-		-		-
Collars
Hedged Volume (Bbls/d)	WTI		425		1,025		1,500		-
Average floor price ($/Bbls)		$	90.00	$	90.00	$	80.00		-
Average ceiling price ($/Bbls)		$	106.50	$	110.00	$	102.00		-

Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		26,622		7,191		11,350		10,445
Average price ($/MMBtu)		$	6.18	$	5.34	$	4.27	$	4.47
Basis Swaps (1)
Hedged Volume (MMBtu/d)	Henry Hub		17,066		14,400		-		-
Average price ($/MMBtu)		$	(0.19)	$	(0.19)		-		-
Collars
Hedged Volume (MMBtu/d)	Henry Hub		4,966		18,000		630		595
Average floor price ($/MMBtu)		$	5.74	$	5.00	$	4.00	$	4.00
Average ceiling price ($/MMBtu)		$	7.51	$	7.48	$	5.55	$	6.15
Puts
Hedged Volume (MMBtu/d)	Henry Hub		-		420		11,350		10,445
Average price ($/MMBtu)			-	$	4.00	$	4.00	$	4.00

⁽¹⁾

Our natural gas basis swaps are used to hedge the differential between Henry Hub and various points.

For more information on the oil and natural gas derivative positions and resulting adjusted prices in place as of December 31, 2013, see Part II, Item 7A. Quantitative and Qualitative Disclosure About Market Risk.

Interest Rate Derivatives

In an effort to mitigate exposure to changes in market interest rates, we have entered into interest rate swaps that effectively fix the LIBOR component on our outstanding variable rate debt. The changes in the fair value of these instruments are recorded in current earnings.

During the year ended December 31, 2013, we entered into new interest rate swaps with settlement dates through 2016. All of the new contracts were entered into with various counterparties.

Counterparty Exposure

As of December 31, 2013, our open commodity derivative contracts were in a net asset position. All of our commodity derivative contracts are with major financial institutions. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss. Although we have the ability to elect to enter into netting agreements with certain of our counterparties, we have properly presented all asset and liability positions without netting. As of December 31, 2013, all of our counterparties have performed pursuant to their commodity derivative contracts.

The following table presents our commodity derivative asset and liability positions with our counterparties both before and after credit risk adjustments as of December 31, 2013:


		Credit Risk
		Gross		Adjustment		Adjusted
Assets	$	90,509	$	(893)	$	89,616
Liabilities		(7,228)		135		(7,093)
Net		83,281		(758)		82,523

Cash Flows

Cash flows provided (used) by type of activity were as follows for the periods indicated:


		Year Ended		Year Ended		Year Ended
		December 31,		December 31,		December 31,
		2013		2012		2011
Net cash provided by (used in):
Operating activities	$	202,145	$	227,150	$	112,557
Investing activities		(218,195)		(592,279)		(72,143)
Financing activities		(2,426)		379,532		(25,176)

Operating Activities

Our cash flows from operating activities for 2013 decreased by $25.0 million primarily due to changes in working capital attributable to the oil and natural gas properties acquired in 2012 and the third quarter of 2013, an increase in allocated general and administrative expenses we reimbursed to QRM, a decrease in cash settlements on commodity derivatives and an increase in cash interest expense mainly attributable to the Senior Notes issued in July 2012. These decreases were partially offset by higher operating margins due to the oil and natural gas properties acquired in 2012 and the third quarter of 2013. Our cash flows from operating activities for 2012 increased by $114.6 million primarily due to gains on our commodity contracts as compared to losses in 2011 due to the modification of certain oil derivative contracts during 2011. Also contributing to the increase in operating cash flow during 2012 was the management of our working capital.

Investing Activities

Our principal recurring investing activity is the acquisition and development of oil and natural gas properties. As a result, cash flows from investing activities usually result in a net usage of cash for the periods presented.

Our cash flows used in investing activities for 2013 decreased by $374.1 million primarily due to lower purchase price for oil and gas acquisitions and lower capital spending during the year. Our cash flows used in investing activities for 2012 increased by of $520.1 million primarily due to higher purchase price for oil and gas acquisitions and higher capital spending attributable to our drilling activities during 2012.

Financing Activities

Our cash flows used in financing activities for 2013 decreased by $382.0 million primarily due to the issuance of the Senior Notes in July 2012 and the equity offerings in April and December 2012. Our cash flows from financing activities for 2012 increased by $404.7 million primarily due to the issuance of the Senior Notes in July 2012 and the equity offerings in April and December 2012. These increases were partially offset by net repayments of debt and an increase in distributions to unitholders.

Capital Requirements and Distributions

Capital Requirements

Growth capital expenditures are capital expenditures that are expected to increase our production and the size of our asset base. The primary purpose of growth capital is to acquire producing assets that will increase our distributions per unit and secondarily increase the rate of development of and production from our existing properties in a manner which is expected to be accretive to our unitholders. We are actively engaged in the

acquisition of oil and natural gas properties. We would expect to finance any significant acquisitions of oil and natural gas properties in 2014 through a combination of cash, borrowings under our credit facility and the issuance of debt and equity securities. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. Although we closed acquisitions in 2013, as discussed in Part II, Item 8. Financial Statements and Supplementary Data – Note 4– Acquisitions, we cannot estimate further growth capital expenditures related to acquisitions, including potential acquisitions of producing properties from the Fund, as we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts. Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base. The primary purpose of maintenance capital is to maintain our production and asset base at a steady level over the long-term in order to maintain our distributions per unit.

During the year ended December 31, 2013, we expended $98.5 million of capital expenditures, of which we estimated $69 million to be maintenance capital expenditures. We currently expect 2014 total capital spending for growth and maintenance of our oil and natural gas properties to be approximately $101.6 million. For 2014, we have estimated our maintenance capital expenditures to be approximately $72.0 million.

The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2014. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.

Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations above maintenance capital expenditures. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to finance any significant acquisition of oil and natural gas properties in 2014.

Distributions

Our partnership agreement, as amended, requires that within 45 days after the end of each quarter, or, in our general partner’s sole discretion, in three equal installments within 15, 45, and 75 days following the end of each quarter, we distribute all of our available cash to preferred unitholders, in arrears, and common unitholders of record on the applicable record date, as determined by QRE GP.

In February 2014, the Board of Directors’ approved the third monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which will be paid in March 2014 to the unitholders of record as of March 10, 2014. The third monthly distribution, with the first and second monthly distributions, will aggregate to a total distribution of $0.4875 per unit with respect to the fourth quarter 2013.

On February 22, 2013, our 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. The general partner was eligible to receive a distribution on the Class B units related to the fourth quarter 2012 and will be eligible for future distributions.

On March 2, 2014, we completed the GP Buyout Transaction. For a description of the Class B units that will be and may continue to be issued to the former owners of our general partner in the future, please see Part II, Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities –Deferred Class B Unit Issuances.

On October 3, 2011, we issued 16,666,667 Class C preferred units to the Fund as payment for the October 2011 Transferred Properties. These units receive annualized distributions of $0.84 per Preferred Unit beginning with the cash distribution for the fourth quarter of 2011 paid in February 2012. The annual distribution payable to preferred unitholders will approximate $14.0 million. Beginning on January 1, 2015, distributions on Preferred Units will be the greater of $0.475 per unit or the distribution payable on the Common Units with respect to such quarter.

Contractual Obligations

In the table below, we set forth our contractual cash obligations as of December 31, 2013. The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.


	Payments Due by Period
										After 5
		Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		Years
Total principal debt (1)	$	915,000	$	-	$	615,000	$	-	$	300,000
Estimated interest payments (2)		254,840		49,072		134,080		55,500		16,188
Asset retirement obligations (3)		155,321		4,310		4,582		5,467		140,962
Total	$	1,325,161	$	53,382	$	753,662	$	60,967	$	457,150

⁽¹⁾

Total balance of our senior secured credit facility will mature in April 2017 and our Senior Notes will mature in 2020.

⁽²⁾

Amounts represent the expected cash payments for interest based on the debt outstanding under our credit facility, unused portion of our credit facility, letters of credit issued under our credit facility and the Senior Notes as of December 31, 2013. Rates used to calculate these estimated payments ranged from 2.24% to 3.50% on the unhedged portion of debt outstanding under the credit facility, 3.75% weighted average interest rate on the hedged portion of debt outstanding under the credit facility, a 0.5% commitment fee on the $311.5 million unused portion of the credit facility, 2.0% on the letter of credit outstanding and 9.25% on the Senior Notes.

⁽³⁾

Present value of obligations at December 31, 2013.

Off–Balance Sheet Arrangements

As of December 31, 2013, we had no off–balance sheet arrangements.

Pensions and Post-Retirement Benefits

For discussion of pension and post-retirement benefits, see Part II, Item 8. Financial Statements and Supplementary Data – Note 9 – Pensions and Postretirement Benefits.

Environmental Commitments

For discussion of environmental contingencies, see Part II, Item 8. Financial Statements and Supplementary Data – Note 11 – Commitments and Contingencies.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Part II, Item 8. Financial Statements and Supplementary Data – Note 2 – Summary of Significant Accounting Policies.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Price Risk

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

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

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

We use swaps as a mechanism for managing commodity price risk whereby we pay the counterparty floating prices and receive fixed prices from the counterparty. By entering into swap agreements, we will mitigate the effect on our cash flows of changes in the prices we receive for our oil and natural gas production. These transactions are settled based upon the NYMEX-WTI or Argus LLS price of oil and NYMEX-Henry Hub price of natural gas.

Interest Rate Risk

As of December 31, 2013, we had debt outstanding under our revolving credit facility of $615 million. Our hedging policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. We are exposed to market risk on our open contracts, to the extent of changes in LIBOR. However, the market risk exposure on these contracts is generally offset by the increase or decrease in our interest expense. Further, if our counterparties defaulted, this protection might be limited

as we might not receive the benefits of the contracts. For additional information please refer to Part II, Item 8. Financial Statements and Supplementary Data – Note 7 – Derivative Activities.

Counterparty and Customer Credit Risk

Joint interest receivables arise from entities which own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. See Part I, Item 1. Business for further detail about our significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative contracts expose us to credit risk in the event of nonperformance by counterparties. As of December 31, 2013, our open commodity derivative contracts were in a net asset position with a fair value of $72.1 million. Should one of the counterparties to our commodity derivative contracts not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a losses.

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm begin on page F-1 of this Annual Report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rules 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our Chief Executive Officer, our principal executive officer and Chief Financial Officer, our principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2013. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. As a result of the evaluation, the principal executive officer and the principal financial officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2013.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a -15(f) and 15d -15(f) under the Exchange Act). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in “Internal Control – Integrated Framework (1992)”. As a result of the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2013 based on those criteria.

The effectiveness of our internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Through a purchase business combination, we acquired a controlling interest in ETSWDC in connection with the 2013 East Texas Acquisition on August 6, 2013. We excluded this non-wholly owned subsidiary from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2013. ETSWDC total assets and total revenues represent 2.2% and 2.2%, respectively, of our consolidated financial statement amounts as of and for the year ended December 31, 2013.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

As is the case with many publicly traded partnerships, we do not directly employ officers, directors or employees. Our operations and activities are managed by Quantum Resources Management, an affiliate of our general partner. References herein to our officers, directors and employees are references to the officers, directors and employees of Quantum Resources Management.

Our general partner is not elected by our unitholders and will not be subject to re–election on a regular basis in the future. Prior to the GP Buyout Transaction, unitholders were not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Following the GP Buyout Transaction, our general partner is owned by us and we anticipate that unitholders will begin electing the directors of our general partner in June 2015.

Our general partner owes a fiduciary duty to our unitholders. However, our partnership agreement contains provisions that reduce the fiduciary duties our general partner owes to our unitholders. Our general partner will be liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Whenever possible, our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.

Board Leadership Structure and Role in Risk Oversight

Leadership of our general partner’s board of directors is vested in a chairman of the board. Although our Chief Executive Officer currently does not serve as chairman of the board of directors of our general partner, we currently have no policy prohibiting our current or any future chief executive officer from serving as chairman of the board. The board of directors, in recognizing the importance of the board of directors having the ability to operate independently, determined that separating the roles of chairman of the board and Chief Executive Officer is advantageous for us and our unitholders. Our general partner’s board of directors has also determined that having the Chief Executive Officer serve as a director enhances understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations and ultimately improves the ability of the board of directors to perform its oversight role.

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

Directors and Executive Officers

The following table sets forth certain information regarding the current directors and executive officers of our general partner. There are no family relationships among any of the current directors and executive officers of our general partner. The directors of our general partner serve at the discretion of the owners of our general partner. The officers of our general partner serve at the discretion of the board of directors.


Name	Age	Position with our General Partner
Alan L. Smith	51	Chief Executive Officer and Director
John H. Campbell, Jr.	56	President, Chief Operating Officer and Director
Cedric W. Burgher	53	Chief Financial Officer
Mark P. Castiglione	42	Sr. Vice President, Business Development
Patrick Wagner	49	Sr. Vice President, Western Business Unit
Paul W. Geiger, III	42	Sr. Vice President, Eastern Business Unit
Gregory S. Roden	55	Sr. Vice President, Secretary and General Counsel
Toby R. Neugebauer	43	Director
Donald E. Powell (1)	72	Director
Stephen A. Thorington (2)	58	Director
S. Wil VanLoh, Jr.	43	Director
Richard K. Hebert (3)	62	Director
Donald D. Wolf	70	Chairman of the Board

⁽¹⁾

Chairman of the conflicts committee and member of the audit committee and the compensation committee.

⁽²⁾

Chairman of the audit committee and member of the conflicts committee and the compensation committee.

⁽³⁾

Chairman of the compensation committee and member of the audit committee and the conflicts committee.

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

Alan L. Smith is the Chief Executive Officer and a member of the board of directors of our general partner. Mr. Smith also serves as a Venture Partner and is a member of the Investment Committee with Quantum Energy Partners. Prior to becoming the Chief Executive Officer of Quantum Resources Management in 2009, Mr. Smith served as a Managing Director with Quantum Energy Partners and as Chairman of Chalker Energy Partners II, LLC, both beginning in 2006. From 2003 until 2006, Mr. Smith served as the President and CEO of Chalker Energy Partners I, LLC, a private oil and natural gas exploration and production company he co-founded, which was funded by Quantum Energy Partners. From 2001 until 2003, Mr. Smith served as the Vice President of Business Development at Ocean Energy, Inc. and from 1999 to 2001 he was the Asset Manager for an onshore business unit at Ocean Energy. Prior to 1999, Mr. Smith served in positions of increasing responsibility at XPLOR Energy, Inc., Ryder Scott Company, Burlington Resources and Vastar Resources/ARCO Oil and Gas Company. From June 2006 to June 2007, Mr. Smith served on the board of directors of Linn Energy, LLC. Mr. Smith currently serves on the board of QA Global GP, LLC, the entity controlling the Fund. He also has been a board member of certain entities of Chalker Energy Partners since 2003, and was a board member of Vantage Energy, LLC from 2006 to 2011. He serves as a board member for the Southeastern Region Independent Petroleum Association of America (“IPAA”), an advisory board member of the A&D Watch, a Hart’s publication, and also serves in an advisory capacity to the Texas Tech Department of Petroleum Engineering. Mr. Smith is also a member of the Gulf States chapter of the Young Presidents’ Organization. We believe that Mr. Smith’s extensive experience in the energy industry and his relationships with Quantum Resources Management and Quantum Energy Partners, particularly his service as the Chief Executive Officer of Quantum Resources Management, bring important experience and skill to the board of directors.

John H. Campbell, Jr. is the President and Chief Operating Officer and a member of the board of directors of our general partner. Mr. Campbell also serves as a Venture Partner with Quantum Energy Partners. Prior to becoming the President and Chief Operating Officer of Quantum Resources Management in 2009, Mr. Campbell served as a Managing Director with Quantum Energy Partners beginning in 2003. Prior to joining Quantum Energy Partners in 2003, Mr. Campbell served as Senior Vice President Operations for North America Onshore for Ocean Energy, Inc. from 1998 to 2003, where he was responsible for the company’s extensive onshore oil and natural gas operations. He joined Ocean in 1998 from Burlington Resources, Inc. where, over a period of eleven years, he served in a variety of engineering, operational and management positions. Prior to Burlington, he was a field engineer with Schlumberger Ltd. from 1982 to 1985. Over the years, he has led the technical and capital allocation efforts for major onshore and offshore assets, as well as the evaluation of numerous property acquisitions and mergers. Mr. Campbell also serves on the board of QA Global GP, LLC, the entity controlling the Fund. We believe that Mr. Campbell’s extensive experience in the energy industry, particularly his background and experience in the engineering and operational aspects of exploration and production activities, bring important experience and skill to the board of directors.

Cedric W. Burgher has been the Chief Financial Officer of our general partner since its inception in 2010. Mr. Burgher formerly served as a Managing Director of Quantum Energy Partners from May 2008 to October 2010. Since 2009, Mr. Burgher has served as a director of Quantum Energy Partners' portfolio company, Chalker Energy Partners II and III, LLC. Prior to joining Quantum, Mr. Burgher served as the Chief Financial Officer of KBR, Inc., a global engineering, construction and services company, from 2005 until 2008. Prior to KBR, Mr. Burgher served as the Chief Financial Officer of Burger King Corporation, and prior to that he held

management positions with Halliburton Company, Enron, EOG Resources and Baker Hughes following several years in the banking industry. Mr. Burgher is a Chartered Financial Analyst (CFA).

Mark Castiglione is Senior Vice President, Business Development for QR Energy. Mr. Castiglione also serves as Senior Vice President, Business Development for Quantum Resources Management. He is responsible for leading the company's business development, acquisition and divestiture efforts. Prior to joining Quantum in early 2010, Mark was the Vice President of Acquisitions & Divestitures for El Paso Corporation from November 2009 to February 2010. He served as Vice President – Business Development for El Paso Exploration & Production from June 2008 to October 2009 and as Director – Business Development from March 2007 to June 2008. Mark's background includes oil and gas experience in business development, corporate finance, asset management and engineering. His positions prior to El Paso include Group Lead of the Deep Bossier Development for EnCana Oil & Gas (USA) Inc. and Manager of Worldwide Acquisitions & Divestitures for Burlington Resources. Mark also previously held positions in the investment banking group of Simmons & Company International and Enron Corporation. He began his career as reservoir engineer for Burlington Resources in the San Juan Basin. Mark serves on the advisory board of the department of Petroleum Engineering at Texas Tech University.

Paul W. Geiger, III serves as Senior Vice President, Eastern Business Unit for QR Energy. Mr. Geiger also serves as Senior Vice President, Eastern Business Unit for Quantum Resources Management. He has responsibility for production engineering, asset operations and exploitation in the Ark-La-Tex and Gulf Coast areas. Paul's background in domestic onshore operations management and engineering, enhanced oil recovery, and technical and business optimization of assets allow him to lead his team to excellence and best-in-class performance. Prior to joining Quantum in 2009, Paul was employed by Anadarko Petroleum where he served as U.S. Business Development Manager from 2006 to 2008, Manager EHS, Regulatory U.S. Onshore from 2005 to 2006 and as Production Manager from 1998 to 2002. Paul has also served in production operations management, HSE, business, and technical positions of increasing responsibility with Southwestern Energy, Howell Petroleum and Burlington Resources (Meridian Oil).

Patrick J. Wagner is Senior Vice President, Western Business Unit for QR Energy. Mr. Wagner also serves as Senior Vice President, Western Business Unit for Quantum Resources Management. He is responsible for managing the companies’ efforts to maximize asset value in the Permian Basin and Mid-Continent areas. Prior to joining Quantum in early 2012, Pat served as a Managing Director at Scotia Waterous from November 2010 to January 2012, the oil and gas arm of Scotiabank, where he managed the firm’s U.S. technical team and provided technical leadership for mergers, acquisitions and divestitures. Before joining Scotia in 2010, Pat was Vice President of Gulf of Mexico for Devon Energy from June 2009 to August 2010. Pat served as Vice President, Gulf Shelf for Devon Energy from January 2007 to May 2009 and as Manager, International Exploitation from May 2003 to December 2006. Pat played a lead role in Devon’s $4 billion divestiture of their assets in 2010. Prior to joining Devon, Pat served as a Reservoir Engineer Specialist for Ocean Energy from May 2000 to June 2001, as Manager, Acquisitions and Divestitures from June 2001 to February 2002, and as Manager, International Exploitation from February 2002 to April 2004. Prior to joining Ocean, Pat was a Senior Vice President and led the Houston office of a petroleum consulting firm. He began his career as a Project Engineer with Exxon Company, U.S.A.

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

Toby R. Neugebauer is a member of the board of directors of our general partner. Since 1998, Mr. Neugebauer has been a Managing Partner of Quantum Energy Partners, a private equity firm specializing in the energy industry which he co-founded in 1998. Prior to co-founding Quantum Energy Partners, Mr. Neugebauer co-founded Windrock Capital, Ltd., an energy investment banking firm specializing in raising private equity and providing merger, acquisition and divestiture advice for energy companies. Before co-founding Windrock Capital, Ltd. in 1994, Mr. Neugebauer was an investment banking analyst in Kidder, Peabody & Co.’s Natural Resources Group

where he worked on corporate debt and equity financings, mergers, acquisitions and other highly structured transactions for energy and energy-related companies. Mr. Neugebauer currently serves on the boards of a number of portfolio companies of Quantum Energy Partners, all of which are private energy companies. Mr. Neugebauer also serves on the board of QA Global GP, LLC, which is the entity controlling the Fund. From January through June 2006, Mr. Neugebauer served as the Chairman of the board of directors of Linn Energy, LLC, and he was involved in the founding of Legacy Reserves LP. Mr. Neugebauer’s extensive experience from investing in the energy industry over the past thirteen years and serving as a director for numerous private energy companies brings unique and valuable skills to the board of directors.

Donald E. Powell serves on the board of directors of our general partner. Mr. Powell is chairman of the conflicts committee and a member of the audit committee and compensation committee. He served as a member of the board of directors of Bank of America Corporation since 2009 to 2013 and a member of the board of directors of Stone Energy Corporation since 2008. Mr. Powell served as the Federal Coordinator of Gulf Coast Rebuilding from 2005 until 2008. Prior to 2005, Mr. Powell was the 18th Chairman of the Federal Deposit Insurance Corporation, where he served from 2001 until 2005. Mr. Powell served on the Board of Regents of Texas A&M University System from 1995 to 2001 (served as chairman for four years). Mr. Powell previously served as President and Chief Executive Officer of the First National Bank of Amarillo, where he started his banking career in 1971. He was awarded the Presidential Citizens Medal by President George W. Bush in 2008. Mr. Powell was selected to serve as a director because of his vast financial experience, which brings a unique and valuable experience to the audit committee, conflicts committee, compensation committee and board of directors.

Stephen A. Thorington serves on the board of directors of our general partner. Mr. Thorington is chairman of the audit committee and a member of the conflicts and compensation committees. Mr. Thorington served as Executive Vice President and Chief Financial Officer of Plains Exploration & Production Company from 2002 until he retired from that position in 2006. Mr. Thorington also served as Executive Vice President and Chief Financial Officer of Plains Resources, Inc. from 2002 until 2004. From 1999 to 2002 he was Senior Vice President-Finance & Corporate Development of Ocean Energy, Inc. and from 1996 until 1999 he was Vice President-Finance of Seagull Energy Company. Prior to 1996, Mr. Thorington was a Managing Director of Chase Securities and the Chase Manhattan Bank. Mr. Thorington has been a director of KMG Chemicals, Inc. since 2007 and a director of EQT Corporation since 2010. Mr. Thorington’s industry, financial and executive experiences enable him to make valuable contributions to our audit committee, conflicts committee, compensation committee and board of directors.

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

Richard K. Hebert serves on the board of directors of our general partner. Mr. Hebert is chairman of the compensation committee and a member of our audit committee and conflicts committee. Mr. Hebert is a Managing Member of Consolidated Oil & Gas, LLC and Consolidated Property Interests, LLC, both of which he co-founded in 2008-2009. He also serves on the board of Forge Energy. Mr. Hebert has more than 35 years of experience in the upstream oil and gas industry. Mr. Hebert served as the Chairman and Chief Executive Officer of Devonshire Energy, as President, Chief Executive Officer, and Chief Operating Officer of Howell Corporation, and as the Chief Executive Officer of Voyager Energy Corp, which he co-founded, prior to Voyager being acquired by Howell. Mr.

Hebert also served in executive and managerial roles at Burlington Resources and managerial and technical roles at Mobil Oil, Inc. and Superior Oil, Inc. He began his career in 1974 as a production and reservoir engineer with Amoco Production Company. Mr. Hebert’s industry and executive experiences enable him to make valuable contributions to our compensation committee, audit committee, conflicts committee, and board of directors.

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

Composition of the Board of Directors

Our general partner’s board of directors consists of eight members. The board of directors holds regular and special meetings at any time as may be necessary. Regular meetings may be held without notice on dates set by the board from time to time. Special meetings of the board or meetings of any committee thereof may be called by written request authorized by any member of the board or a committee thereof on at least 48 hours prior written notice to the other members of the board or committee. A quorum for a regular or special meeting will exist when a majority of the members are participating in the meeting either in person or by telephone conference. Any action required or permitted to be taken at a board meeting may be taken without a meeting, without prior notice and without a vote provided a consent or consents in writing, setting forth the action so taken, are signed by at least as many members of the board as would have been required to take such action at a meeting of the board or such committee.

Non-Management Executive Sessions and Unitholder Communications

NYSE listing standards require regular executive sessions of the non-management directors of a listed company, and an executive session for independent directors at least once a year. At each quarterly meeting of our general partner’s board of directors, all of the directors will meet in an executive session. At least annually, our independent directors will meet in an additional executive session without management participation or participation by non-independent directors. Don Powell presides over all non-management independent executive sessions.

Interested parties can communicate directly with non–management directors by mail in care of QR Energy, LP, 1401 McKinney Street, Suite 2400, Houston, Texas 77010. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded.

Committees of the Board of Directors and Independence Determination

Our general partner’s board of directors has established an audit committee, a conflicts committee and a compensation committee. The charters of each committee are posted under the “Investor Relations” section of our website at www.qrenergylp.com.

Because we are a limited partnership, the listing standards of the NYSE do not require that we or our general partner have a majority of independent directors or a compensation committee, or nominating and corporate

governance committee of the board of directors. We are, however, required to have an audit committee, all of whose members are required to be “independent” under NYSE standards.

Pursuant to the NYSE listing standards, a director will be considered independent if the board determines that he or she does not have a material relationship with our general partner or us (either directly or indirectly as a partner, unitholder or officer of an organization that has a material relationship with our general partner or us) and otherwise meets the board’s stated criteria for independence. The NYSE listing standards specify the criteria by which the independence of directors will be determined, including guidelines for directors and their immediate family members with respect to employment or affiliation with us or with our independent public accountants. Our general partner’s board of directors has affirmatively determined Messrs. Thorington, Hebert and Powell satisfy the NYSE and SEC requirements for independence.

Audit Committee

The audit committee consists of Messrs. Thorington (Chairman), Hebert, and Powell, all of whom meet the independence and experience standards established by the NYSE and the Exchange Act for audit committee members. Our general partner’s board of directors has determined that each of Messrs. Thorington and Powell is an “audit committee financial expert” as defined under SEC rules.

The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee also reviews our oil and natural gas reserve estimation processes.

The audit committee has the sole authority and responsibility to retain and terminate our independent registered public accounting firm, resolve disputes with such firm, approve all auditing services and related fees and the terms thereof and pre–approve any non–audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and meets with the audit committee on a regularly scheduled basis. The audit committee may also engage the services of advisors and accountants as it deems advisable.

Conflicts Committee

The conflicts committee consists of Messrs. Powell (Chairman), Hebert and Thorington, all of whom meet the independence standards established by the NYSE. The conflicts committee reviews specific matters that the board of directors believes may involve conflicts of interest. The conflicts committee will then determine if the conflict of interest has been resolved in accordance with our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Compensation Committee

The NYSE rules do not require a publicly traded limited partnership’s board of directors to have a standing compensation committee. However, our general partner’s board of directors has elected to establish a compensation committee. The compensation committee consists of Messrs. Hebert (Chairman), Powell and Thorington, all of whom meet the independence standards established by the NYSE for compensation committee members. The compensation committee also periodically reviews specific matters and makes recommendations to the board of directors related to the compensation for executive officers, compensation for directors and the Partnership’s issuance and award of units under its long-term incentive program. The compensation committee may also engage the services of advisors as it deems advisable to carry out its duties.

Meetings and Other Information

During 2013, the board of directors held six regularly scheduled and special meetings, the audit committee held eight meetings, the conflicts committee held nine meetings and the compensation committee held four meetings. None of our directors attended fewer than 75% of the aggregate number of meetings of the board of directors and committees of the board on which the director served.

Our partnership agreement provides that the general partner manages and operates us and that, unlike holders of common stock in a corporation, unitholders only have limited voting rights on matters affecting our business or governance. Accordingly, we do not hold annual meetings of unitholders.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires executive officers and directors of our general partner and persons who beneficially own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act to file certain reports with the SEC and the NYSE concerning their beneficial ownership of such securities.

Based solely on a review of the copies of reports on Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from the executive officers and directors of our general partner, we believe that during the year ended December 31, 2013 the officers and directors of our general partner and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a).

Corporate Code of Business Conduct and Ethics

The corporate governance of our general partner is, in effect, the corporate governance of our partnership, subject in all cases to any specific unitholder rights contained in our partnership agreement.

QRE GP, LLC has adopted a corporate code of business conduct and ethics that applies to all officers, directors and employees of QRE GP, LLC and its affiliates, including the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer of our general partner. A copy of our corporate code of business conduct and ethics and our financial code of ethics is available on our website at www.qrenergylp.com. We will provide a copy of our code of ethics to any person, without charge, upon request to QRE GP, LLC, 1401 McKinney Street, Suite 2400, Houston, Texas 77010, Attn: Corporate Secretary.

Reimbursement of Expenses of Our General Partner

Our general partner does not receive any compensation for its management of our partnership. Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Under the terms of the Services Agreement between our general partner and Quantum Resources Management (the “Services Agreement”), we pay Quantum Resources Management a fee for general and administrative services undertaken for our benefit and for our allocable portion of the premiums on insurance policies covering our assets. In addition, we reimburse Quantum Resources Management for the costs of employee, officer and director compensation and benefits properly allocable to us, as well as for other expenses necessary or appropriate to the conduct of our business and properly allocable to us.

Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Under the Services Agreement, through December 31, 2012, 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. After December 31, 2012, in lieu of the quarterly administrative services fee, our general partner reimbursed Quantum Resources Management, on a quarterly basis, for the allocable expenses it incurs in its performance under the Services Agreement and we reimbursed our general partner for such payments to Quantum Resources Management. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated by Quantum Resources Management to its affiliates. Quantum Resources Management has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. Until otherwise determined by our general partner, compensation paid to persons who perform services for us, other than officers solely devoted to the Partnership who will have their compensation allocated directly to the Partnership, are allocated based on the percentage of their total time spent on services performed on behalf of the Partnership. Other general and administrative expenses spent directly on behalf the Partnership will be allocated completely to the Partnership and general and administrative

expenses spent indirectly on behalf of the Partnership will be allocated to the Partnership using a ratio determined using equal components of the percent of the Partnership’s production, well count and capital budget as each of these components compare to the production, well count and capital budgets of the Fund and any future fund that QRM may provide services for.

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Overview

Our operations and activities are managed by our general partner. However, neither we nor our general partner directly employ any of the persons responsible for managing our business. Rather, our general partner’s executive officers are employed by Quantum Resources Management (“QRM,” our affiliate), subject to reimbursement by our general partner as follows. Beginning on January 1, 2013, QRM became 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 included direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. The figures reported in the Summary Compensation Table below reflect the portion of the compensation expense accrued by us for the named executive officers’ services, calculated using the quarterly reimbursement of general and administrative charges. Note, however, that the amount of money paid to Quantum Resources Management by our general partner, and then in turn by us, in reimbursement for compensation expenses in 2012 and 2011 is capped at the amount of total administrative service fee under the Services Agreement for the years ended December 31, 2011 and 2012. The figures reported in the Summary Compensation Table below reflect the portion of the compensation expense accrued by us for the named executive officers’ services prior to application of the cap on our reimbursement obligation. As such, the amounts reported in the Summary Compensation Table may reflect larger figures than the cost actually incurred by us for the named executive officers’ services. Please read Part III, Item 13. Certain Relationships and Related Party Transactions – Ownership in Our General Partner by the Management of the Fund – Services Agreement for more information on the Services Agreement.

We commenced our business operations at the time of our initial public offering on December 22, 2010. Other than for Messrs. Smith and Burgher, for whom our general partners’ board of directors made compensation decisions, our general partner’s board of directors does not have responsibility and authority for compensation-related decisions for our named executive officers in respect of their service to us, other than with respect to equity compensation awards. Quantum Resources Management has general responsibility and authority for compensation-related decisions for our named executive officers in respect of their service to us, the Fund and other entities. Because it is a private company, Quantum Resources Management has not historically had any formal compensation policies or practices. Rather, all compensation decisions, including those for our named executive officers, have been made at the discretion of the individuals who control Quantum Resources Management, including Donald D. Wolf, Toby R. Neugebauer and S. Wil VanLoh, Jr., all of whom are directors of our general partner.

Objectives of our Compensation Program

As we further develop our business, our goal is to design our executive compensation program to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our unitholders and to reward success in reaching such goals. We expect that we will use three primary elements of compensation to fulfill that design – base salary, cash bonuses and long-term equity incentive awards under the Long Term Incentive Plan (the “LTIP”). Cash bonuses and equity incentives (as opposed to base salary) represent the performance driven elements. They are also flexible in application and can be tailored to meet our objectives. The determination of each of our named executive officers’ cash bonuses, if any, will reflect their relative contributions to achieving or exceeding annual goals of the partnership and the determination of specific individual’s long-term incentive awards will be based on their expected contribution in respect of longer term performance objectives.

2013 Named Executive Officers

This compensation discussion and analysis, or CD&A, provides general information about the compensation paid to our Chief Executive Officer, Chief Financial Officer, and the three most highly compensated executive officers of our general partner (other than our Chief Executive Officer and Chief Financial Officer), identified in the following table, who we refer to in this CD&A and the tables that follow as our “named executive officers.” The four Sr. Vice Presidents, Mark Castiglione, Paul W. Geiger, III, Patrick Wagner and Gregory Roden are compensated at very similar levels and Company has determined to include each of them as named executive officers.


Name		Principal Position
Alan L. Smith		Chief Executive Officer
Cedric W. Burgher		Chief Financial Officer
Mark Castiglione		Sr. Vice President, Business Development
Paul W. Geiger, III		Sr. Vice President, Eastern Business Unit
Patrick Wagner		Sr. Vice President, Western Business Unit
Gregory S. Roden		Sr. Vice President, Secretary and General Counsel

Compensation Decisions for Fiscal 2013

In 2013, decisions regarding the compensation paid to Messer’s Smith and Burgher were generally made by our general partner’s board of directors. Mr. Burgher’s services during 2013 were performed exclusively for the partnership.

Messrs. Castiglione, Geiger, Wagner and Roden performed services both for us and the Fund during 2013. Quantum Resources Management had the responsibility and authority for compensation-related decisions (including base salary and cash bonus) for Messrs. Castiglione, Geiger, Wagner and Roden during fiscal 2013; however, our general partner’s board of directors made decisions regarding their 2013 awards granted to them under our general partner’s long-term incentive plan (the “LTIP”), described below. Our general partner reimbursed Quantum Resources Management for a portion of the base salary for each of Messrs. Castiglione (whose salary is currently set at $300,000 per year), Geiger (currently $300,000), Wagner (currently $300,000), and Roden (currently $300,025), cash bonus, and the cost of their benefits.

Finally, Mr. Smith also performed services for both us and the Fund during 2013. Quantum Resources Management had the responsibility and authority to set the base salary and benefits for Mr. Smith related to the services performed for us, our general partner’s board of directors after review of the recommendation of our compensation committee had the authority to make grants under our general partner’s LTIP to Mr. Smith for services performed for us, and Mr. Smith’s compensation for services performed for the Fund was determined and paid by the sponsors of the Fund. Mr. Smith’s salary was set prior to 2013 at a level that allows him to be eligible to receive benefits under the Quantum Resources Management plans (for example, health and dental insurance plans). Mr. Smith does not receive annual cash bonuses for the services he provides to us, because his primary cash compensation is set and paid by the sponsors of the Fund. Mr. Smith received grants under our general partner’s LTIP in 2013 (the material terms of which are described in more detail below) in lieu of a higher base salary for the services provided to us. Our general partner’s board of directors after review of the recommendation of our compensation committee elected to grant restricted units to Mr. Smith rather than increase his base salary, because restricted units have a stronger retentive benefit. Seventy-five percent of the restricted units provided to Mr. Smith are performance based units subject to adjustment on the third anniversary of the grant, i.e. an increase (up to 225% of such performance based units) or decrease (to 0% of such performance based units) based on a combination of QRE’s total unit performance and unit performance relative to certain of QRE’s peers.

Annual Cash Bonus

We include a discretionary annual cash bonus as part of our compensation program because we believe this element of compensation helps to motivate management to achieve key operational objectives by rewarding the achievement of these objectives. The annual cash bonus also allows us to be competitive from a total remuneration standpoint. For 2013 performance, our Chief Executive Officer made recommendations to our compensation committee which, after review, made its recommendation to our general partner’s board of directors regarding the level of annual bonus he felt appropriate for Mr. Burgher, for services provided during 2013. Our general partner’s

board of directors reviewed the recommendations made by our Chief Executive Officer and approved cash bonuses awarded to Mr. Burgher, in the amounts enumerated below.

The board of directors generally targets between 50% and 75% of base salary for performance deemed by our board of directors to be good and exceptional, respectively, with the possibility of no bonus for poor performance and higher for exceptional corporate or individual performance. When determining the amounts of the cash bonuses awarded for 2013, the general partner’s board of directors took into account our Chief Executive Officer’s recommendations as well as its belief that our executives’ efforts directly affected our success in 2013, in particular, by contributing to our achievement for the following milestones:

Maintained quarterly distributions at $0.4875/unit;

Successfully completed an acquisition of oil and gas assets in East Texas from a private seller for $107.8 million cash, subject to customary closing price adjustments, and closed on various additional small oil and gas acquisitions in East Texas with an aggregate purchase price of $22.6 million in cash.

Achieved reasonable strong operating performance within production guidance and maintained strong liquidity; and

Increased proved reserves to 109.1 million barrels of oil equivalent, up 10% from 2012.

For 2013 performance, Mr. Burgher was awarded a cash bonus of $225,905 paid by Quantum Resources Management that is reimbursable by our general partner under the Services Agreement.

For 2013 performance, Mr. Castiglione was awarded a cash bonus of $229,688 of which $184,838 reflects the portion of the cash paid by Quantum Resources Management that is reimbursable by our general partner under the Services Agreement.

For 2013 performance, Mr. Geiger was awarded a cash bonus of $229,688 of which $184,838 reflects the portion of the cash paid by Quantum Resources Management that is reimbursable by our general partner under the Services Agreement.

For 2013 performance, Mr. Wagner was awarded a cash bonus of $229,688 of which $184,838 reflects the portion of the cash paid by Quantum Resources Management that is reimbursable by our general partner under the Services Agreement.

For 2013 performance, Mr. Roden was awarded a cash bonus of $229,688 of which $184,838 reflects the portion of the cash paid by Quantum Resources Management that is reimbursable by our general partner under the Services Agreement.

Mr. Smith will not receive a bonus for the 2013 year. With respect to his services to us, Mr. Smith agreed to receive only a minimum salary for benefits eligibility and his LTIP awards for the 2013 year.

Compensation Consultant

To assist us in evaluating our compensation program for 2013, our general partner’s board of directors retained Pearl Meyer & Partners, a compensation consulting firm, on our behalf, to review our proposed compensation programs designed to provide long term retention incentives to our named executive officers and those professional employees of Quantum Resources Management that provide services to us pursuant to the Services Agreement. This information was used by us to obtain a general sense of the market levels of compensation paid by other companies in our industry and to establish compensation programs and awards that most effectively incentivize our executives to achieve our longer-term goals and can also be used as a tool to promote retention of our key employees.

Long-Term Incentive Plan Awards

Awards were granted to our named executive officers under the LTIP to promote achievement of our long term strategic objectives and enhance retention. The LTIP allows for the grant of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. As of December 31, 2013, there were 469,426 common units that remain available for issuance under the LTIP.

In 2013, our general partner granted time-based and performance-based restricted units under the LTIP that are designed to balance the partnership’s need to retain critical leadership and encourage the delivery of long-term value to our unitholders. The division between time-based and performance-based awards was determined based on their respective levels of authority and responsibility. The portion of each of our named executive officers’ 2013 LTIP awards that was granted as performance-based restricted units rather than time-based units is shown below:


		Portion of 2013 LTIP Award
		Granted as Performance-Based
Named Executive Officer		Restricted Units
Alan L. Smith		75%
Cedric W. Burgher		50%
Mark Castiglione		25%
Paul W. Geiger, III		25%
Patrick Wagner		25%
Gregory S. Roden		25%

All time-based restricted units will vest in three equal installments over a three year period, generally subject to the executive’s continued employment. All performance-based restricted units cliff vest at the end of a three-year performance period. The number of units that could be earned under each performance-based restricted unit award is determined according to a payout percentage that ranges from 0% to 225% of the number of performance-based restricted units granted based on a combination of the growth in our unit price during the performance period and our relative total unitholder return as compared to a selected peer group. For performance-based restricted units granted in 2013, the relevant peer group was comprised of 9 of our peer master limited partnerships: LRR Energy, L.P., Memorial Production Partners LP, Breitburn Energy L.P., EV Energy Partners LP, Mid-Con Energy Partners, LP, Legacy Reserves, LP, Vanguard Natural Resources, LLC, Linn Energy, LLC, and Atlas Resource Partners, L.P. This peer group was selected based on upstream oil and gas master limited partnerships. The 2013 awards will pay out, if at all, based upon where we fall within our peer group over the full three year performance period for the award. There is not an established “threshold” level of performance required for payout for the 2013 awards, but “target” levels of awards would be settled if we fall within the 55% percentile of our peers and the “maximum” amounts would be paid only if we are number one among our peers in relative total unitholder return and have obtained a 30% unit price growth at the end of the three year performance period. Awards granted to individual named executive officers during 2013 are described in the table titled “Outstanding Equity Awards at Fiscal Year-End” and accompanying footnotes set forth later in this Section.

The restricted units granted to our named executive officers will also become fully vested upon a change of control of the partnership or if the named executive officer’s employment is terminated due to his death or disability. Each of the restricted unit awards includes unit distribution rights (“UDRs”), which enable our named executive officers to receive cash distributions on the restricted units to the same extent as our unitholders receive cash distributions on our common units. Such distributions are paid to the named executive officer at the same time as cash distributions are paid to our common unitholders. With respect to future grants under the LTIP, the board of directors of our general partner intends to continue to grant primarily restricted unit awards with UDRs under the plan. These awards are intended to align the interests of key employees (including our named executive officers) with those of our unitholders.

Other Benefits

We do not maintain any retirement or health and welfare plans. Quantum Resources Management does not maintain a defined benefit or pension plan for our named executive officers because it believes such plans primarily reward longevity rather than performance. Quantum Resources Management provides a basic benefits package to all of its employees that includes participation in a 401(k) plan and health, disability and life insurance. Employees that provide services to us pursuant to the Services Agreement, including our named executive officers, are entitled to

the same basic benefits. In 2013, the Quantum Resources Management dollar-for-dollar matching contribution under the 401(k) plan was converted to a safe harbor dollar-for-dollar matching contribution on the first 3% of eligible compensation and a 50% company match on the next 2% of eligible compensation contributed to the plan, subject to the applicable contribution limits set forth in the Internal Revenue Code. An additional discretionary employer contribution may also be made under the 401(k) plan on behalf of eligible employees who meet certain conditions and subject to certain limitations under applicable law; however, no such additional contributions were made during 2013. Quantum Resources Management does not provide any perquisites or other personal benefits with a total value in excess of $10,000 to any of its named executive officers.

Compensation Committee Report

The compensation committee of the board of directors of our general partner has reviewed and discussed the foregoing Compensation Discussion and Analysis with the management of our general partner, and based on such review and discussion, has recommended to the board of directors of our general partner that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2013. Members of the Compensation Committee are Richard K. Hebert, Chairman, Donald E. Powell and Stephen A. Thorington.

Compensation Expectations for 2014

In fiscal 2014, Mr. Burgher will continue to devote all of his time to our business. As a result, the board of directors of our general partner will have sole responsibility and authority taking into consideration recommendations made by our compensation committee for compensation-related decisions relating to Mr. Burgher for those services. Additionally, our general partner will reimburse Quantum Resources Management for the full amount of Mr. Burgher’s base salary, bonus and benefit cost and we, in turn, will reimburse our general partner for those payments.

We expect that the compensation of our named executive officers for fiscal 2014 will include a significant incentive compensation component based on our performance; however, as of the date of our annual report, no incentive compensation arrangement has been developed. We expect to employ a compensation philosophy that will emphasize pay-for-performance, which will be based on a combination of our partnership’s performance and our named executive officers’ impact on our partnership’s performance. The performance metrics governing incentive compensation will not be tied in any way to the performance of entities other than our partnership (such as Quantum Resources Management, the Fund, Quantum Energy Partners, or any of our other affiliates). We believe this pay-for-performance approach generally aligns the interests of our named executive officers with those of our unitholders and at the same time enables us to maintain a lower level of base overhead in the event our operating and financial performance fails to meet expectations.

Tax Deductibility of Compensation

With respect to the deduction limitations imposed under Section 162(m) of the Internal Revenue Code, we are a limited partnership and do not meet the definition of a “corporation” under Section 162(m). Accordingly, such limitations do not apply to compensation paid to our named executive officers.

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Summary Compensation Table

The following table sets forth certain information with respect to compensation of our named executive officers for the fiscal year ended December 31, 2013. Compensation expense was allocated between us and the Fund based on the estimated use of expended employee time and other indirect expenses based on multiple operating metrics. The amount of money paid to Quantum Resources Management by the general partner, and then in turn by us in reimbursement for compensation expenses in 2012 and 2011 is capped at the amount of the total administrative services fee under the Services Agreement for the years ended December 31, 2012 and 2011. The figures reported in the Summary Compensation Table below reflect the portion of the compensation expense accrued by us for the named executive officers’ services. As such, the amounts reported in the Summary Compensation Table may reflect larger figures than the cost actually incurred by us for the named executive officers’ services. Please read Part III, Item 13. Certain Relationships and Related Party Transactions – Ownership in Our General Partner by the Management of the Fund – Services Agreement for more information on the Services Agreement.


Name	Year		Salary (1)		Bonus (2)		Stock Awards (3)		All Other Compensation (4)		Total Compensation
Alan L. Smith	2013	$	38,500	$	-	$	667,922	$	14,477	$	720,899
Chief Executive Officer	2012	$	42,740	$	-	$	602,762	$	16,676	$	662,178
	2011	$	34,732	$	-	$	200,006	$	8,105	$	242,843
Cedric W. Burgher	2013	$	302,500	$	225,905	$	973,258	$	37,991	$	1,539,654
Chief Financial Officer	2012	$	275,000	$	192,500	$	703,032	$	27,773	$	1,198,305
	2011	$	275,000	$	236,514	$	-	$	18,888	$	530,402
Mark Castiglione	2013	$	231,000	$	184,838	$	269,026	$	32,255	$	717,119
Sr. Vice President, Business	2012	$	238,632	$	179,510	$	270,223	$	33,708	$	722,073
Development	2011	$	232,200	$	174,150	$	107,991	$	18,218	$	532,559
Paul W. Geiger, III	2013	$	231,000	$	184,838	$	269,026	$	35,657	$	720,521
Sr. Vice President , Eastern	2012	$	238,632	$	179,510	$	395,225	$	31,066	$	844,433
Business Unit	2011	$	215,000	$	161,250	$	-	$	27,797	$	404,047
Patrick Wagner	2013	$	231,000	$	184,838	$	269,026	$	22,331	$	707,195
Sr. Vice President , Western	2012	$	238,632	$	179,510	$	270,223	$	24,794	$	713,159
Business Unit	2011	$	-	$	-	$	-	$	-	$	-
Gregory S. Roden	2013	$	231,019	$	184,838	$	289,031	$	27,523	$	732,411
Sr. Vice President, Secretary	2012	$	235,070	$	176,305	$	395,225	$	36,235	$	842,835
and General Counsel	2011	$	173,658	$	161,250	$	-	$	16,533	$	351,441

⁽¹⁾

For all named executive officers other than Mr. Burgher, the figures in this column reflect the portion of the base salaries paid by Quantum Resources Management to those of our named executive officers referenced above that is reimbursable by our general partner under the Services Agreement.

⁽²⁾

For Messrs. Roden, Geiger, Wagner and Castiglione, the figures in this column reflect the portion of the annual cash bonus paid by Quantum Resources Management that is reimbursable by our general partner, and in turn by us, under the Services Agreement. For Mr. Burgher, in 2011, the figure in this column represents the portion of his annual cash bonus paid by Quantum Resources Management and reimbursed by our general partner.

⁽³⁾

Reflects the aggregate grant date fair value of time-based vesting restricted unit awards granted under the LTIP calculated by multiplying the number of restricted units granted to each executive by the grant date fair value on date of grant ($18.00 with respect to the grant of 13,889 restricted unit awards made to Mr. Smith on April 22, 2013, $18.00 with respect to grants of 34,722, 13,542, 12,605, 12,605, and 12,605 restricted unit awards made to Messrs. Burgher, Roden, Geiger, Castiglione, and Wagner on April 22, 2013, respectively, $18.19 with respect to grants of 27,055, 19,340, 19,340, 12,468 and 12,468 restricted unit awards made to Messrs. Burgher, Roden, Geiger, Castiglione, and Wagner on July 25, 2012, respectively, $20.28 with respect to the grant of 5,325 restricted units made to Mr. Castiglione on November 1, 2011, and $22.26 with respect to the grant of 8,985 restricted units made to Mr. Smith on March 9, 2011). Also reflects the aggregate grant date fair value of performance-based vesting restricted unit awards granted under the LTIP calculated by multiplying the number of performance units granted by the grant date fair value ($10.03 with respect to the grant of 41,667 performance unit awards made to Mr. Smith on April 22, 2013, $10.03 with respect to the 34,722, 4,514, 4,201, 4,201, and 4,201 performance unit awards made to Messrs. Burgher, Roden, Geiger, Castiglione, and Wagner, respectively, on April 22, 2013, $10.26 with respect to the grant of 37,109 performance unit awards made to Mr. Smith on August 22, 2012, $10.45 with respect to the 20,182, 4,156, 4,156, 4,156 and 4,156 of performance unit awards made to Messrs. Burgher, Roden, Geiger, Castiglione and Wagner respectively, on July 25, 2012). These values were computed in accordance with FASB ASC Topic 718. See Part II, Item 8. Financial Statements and Supplementary Data – Note 15 – Equity-Based Compensation to our consolidated financial statements for fiscal 2013 for additional detail regarding assumptions underlying the value of these equity awards.

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⁽⁴⁾

The figures in this column reflect the portion of (i) matching contributions under the Quantum Resources Management 401(k) plan, (ii) medical ER, (iii) life insurance premiums, including AD&D premium and (iv) unused vacation paid by Quantum Resources Management to our named executive officers referenced above that is reimbursable by our general partner under the Services Agreement (other than for Mr. Burgher who is allocated at 100%, each other executive is allocated based on the allocation of services, which was 77% for 2013), prior to the application of the cap of 3.5% of Adjusted EBITDA applied under the Services Agreement.

Grants of Plan-Based Awards for Fiscal 2013


		Estimated Future Payouts Under		All Other Units
		Equity Incentive Plan Awards		Awards:		Grant Date Fair Value
Name	Grant Date	Target(1)	Maximum(2)	Number of Units (3)		of Unit Awards (4)
Alan L. Smith	4/22/2013	41,667	93,750	13,889	$	667,922
Cedric W. Burgher	4/22/2013	34,722	78,124	34,722	$	973,258
Mark Castiglione	4/22/2013	4,201	9,452	12,605	$	269,026
Paul W. Geiger	4/22/2013	4,201	9,452	12,605	$	269,026
Patrick Wagner	4/22/2013	4,201	9,452	12,605	$	269,026
Gregory S. Roden	4/22/2013	4,514	10,156	13,542	$	289,031

⁽¹⁾

Represents the target number of units that can be earned under the performance-based restricted unit awards granted under the LTIP if the payout (rounded to the nearest whole unit) percentage is 100%. The portions of the restricted unit awards granted under the LTIP that are subject to performance-based vesting conditions are as follows: 75% of Mr. Smith’s award, 50% of Mr. Burgher’s award, 25% of the awards granted to Messrs. Castiglione, Geiger, Wagner and Roden. The awards do not have a threshold payout amount.

⁽²⁾

Represents the maximum number of units that can be earned under the performance-based restricted unit awards granted under the LTIP, if the payout percentage is 225%.

⁽³⁾

Reflects the portion of the restricted unit awards granted under the LTIP (rounded to the nearest whole unit) that are subject to time-based vesting conditions (25% of Mr. Smith’s award, 50% of Mr. Burgher’s award, 75% of the awards granted to Messrs. Castiglione, Geiger, Wagner and Roden).

⁽⁴⁾

Reflects the aggregate grant date fair value of the restricted unit awards granted under the LTIP. These values were computed in accordance with FASB ASC Topic 718. See Part II, Item 8. Financial Statements and Supplementary Data – Note 15 – Equity-Based Compensation to our consolidated financial statements for fiscal 2013 for additional detail regarding assumptions underlying the value of these equity awards.

Narrative Description to the Summary Compensation Table and the Grant of Plan-Based Awards Table for the 2013 Fiscal Year

We have not entered into employment agreements with any of our named executive officers.

On April 22, 2013, the board of directors of our general partner granted Messrs. Smith, Burgher, Geiger, Wagner, Castiglione, and Roden awards of 55,556, 69,444, 16,806, 16,806, 16,806, and 18,056, restricted units, respectively, under the LTIP. The portions of the restricted unit awards granted under the LTIP that are subject to performance-based vesting conditions are as follows: 75% of Mr. Smith’s award, 50% of Mr. Burgher’s award, 25% of the awards granted to Messrs. Castiglione, Geiger, Wagner, and Roden.

A discussion of the material terms of these awards is included in the “Compensation Discussion and Analysis” above.

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Outstanding Equity Awards at Fiscal Year-End

The following table sets forth certain information with respect to outstanding equity awards at December 31, 2013.


Name	Number of Time Based Units That Have Not Vested (#)	Market Value of Time Based Units That Have Not Vested ($) (14)	Number of Performance Based Units That Have Not Vested (#)	Market or Payout Value of Performance Based Units That Have Not Vested ($) (15)	Total Number of Restricted Units That Have Not Vested (#)	Total Market or Payout Value of Restricted Units That Have Not Vested ($)
Alan L. Smith (1), (2), (3)	25,131	430,242	78,775	915,530	103,906	1,345,772
Cedric W. Burgher (4), (5)	82,759	1,416,834	54,904	674,697	137,663	2,091,531
Mark Castigilone (6), (7)	22,692	388,487	8,357	95,712	31,049	484,199
Paul W. Geiger, III (8), (9)	25,498	436,526	8,357	95,712	33,855	532,238
Patrick Wagner (10), (11)	20,917	358,099	8,357	95,712	29,274	453,811
Gregory S. Roden (12), (13)	26,435	452,567	8,670	100,299	35,105	552,866

⁽¹⁾

Mr. Smith was granted an award of 8,985 restricted units on March 9, 2011. These restricted units vest in equal one-third increments over a 36-month period. As such, 2,995 restricted units from such awards vested on March 9, 2012 and 2,995 restricted units from such awards vested on March 9, 2013. The remaining unvested units under such award will vest with respect to 2,995 restricted units on March 9, 2014, provided that Mr. Smith has continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the Initial Date through each applicable vesting date.

⁽²⁾

Mr. Smith was granted an award of 49,478 restricted units on August 22, 2012. Twenty-five percent of this award (12,370 units) is comprised of time vested units that vest in equal one-third increments over a 36-month period commencing on July 1, 2012 (i.e. approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the restricted units will be 100% vested on July 1, 2015, provided that Mr. Smith has continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the Initial Date through each applicable vesting date. Seventy-five percent of the restricted units (37,109 units) provided to Mr. Smith are performance based units subject to adjustment on the third anniversary of the grant, i.e. an increase (up to 225% of such performance based units) or decrease (to 0% of such performance based units) based on a combination of QRE’s total unit performance and relative total shareholder return.

⁽³⁾

Mr. Smith was granted an award of 55,556 restricted units on April 22, 2013. Twenty-five percent of this award (13,889 units) is comprised of time vested units that vest in equal one-third increments over a 36-month period commencing on April 1, 2013 (i.e. approximately 33.3 % vest at each one-year anniversary of the Initial Date, so that the restricted units will be 100% vested on April 1, 2016, provided that Mr. Smith has continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the Initial Date through each applicable vesting date. Seventy-five percent of the restricted units (41,667 units) provided to Mr. Smith are performance based units subject to adjustment on the third anniversary of the grant, i.e. an increase (up to 225% of such performance based units) or decrease (to 0% of such performance based units) based on a combination of QRE’s total unit performance and relative total shareholder return.

⁽⁴⁾

Mr. Burgher was granted an award of 75,000 restricted units on December 22, 2010. These restricted units vest in equal one-fifth increments over a 60-month period, beginning on October 1, 2011. As such, 15,000 restricted units from such award vested on October 1, 2011, 15,000 restricted units from such award vested on October 1, 2012 and 15,000 restricted units from such award vested on October 1, 2013. The remaining unvested units will vest with respect to 15,000 restricted units on each of October 1, 2014, and October 1, 2015, provided Mr. Burgher has continuously provided services to us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. Mr. Burgher was granted an award of 47,237 restricted units on July 25, 2012. Of this award, 27,055 units are comprised of time vested units that vest in equal one-third increments over a 36-month period commencing on the Initial Date (i.e. approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the restricted units will be 100% vested on July 1, 2015), provided Mr. Burgher has continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the Initial Date through each applicable vesting date. Forty-three percent of this award (20,183 units) to Mr. Burgher are performance based units subject to adjustment on the third anniversary of the grant, i.e. an increase (up to 225% of such performance based units) or decrease (to 0% of such performance based units) based on a combination of QRE’s total unit performance and relative total shareholder return.

⁽⁵⁾

Mr. Burgher was granted an award of 69,444 restricted units on April 22, 2013. Of this award (34,722 units are comprised of time vested units that vest in equal one-third increments over a 36-month period commencing on the Initial Date (i.e. approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the restricted units

103

will be 100% vested on April 1, 2016), provided Mr. Burgher has continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the Initial Date through each applicable vesting date. Fifty percent of this award (34,722 units) awarded to Mr. Burgher are performance based units subject to adjustment on the third anniversary of the grant, i.e. an increase (up to 225% of such performance based units) or decrease (to 0% of such performance based units) based on a combination of QRE’s total unit performance and relative total shareholder return.

⁽⁶⁾

Mr. Castiglione was granted an award of 5,325 restricted units on November 1, 2011. These restricted units vest in equal one-third increments of a 36-month period commencing on the Initial Date. As such, 1,775 restricted units vested on November 1, 2012 and 1,775 restricted units vested on November 1, 2013. The remaining unvested units under such award will vest with respect to 1,775 restricted units on November 1, 2014, provided Mr. Castiglione has continuously provided services to us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. Mr. Castiglione was granted an award of 16,624 restricted units on July 25, 2012. Seventy-five percent (12,468 units) of this award are comprised of time vested units that vest in equal one-third increments over a 36-month period commencing on the Initial Date (i.e., approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the time-vested units will be 100% vested on July 1, 2015, provided Mr. Castiglione has continuously provided services to us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. The remaining twenty-five percent (4,156 units) of this award are performance based units subject to adjustment on the third anniversary of the grant, i.e., an increase (up to 225% of such performance based units) or a decrease (to 0% of such performance based units) based on a combination of QRE’s unit performance and relative total shareholder return.

⁽⁷⁾

Mr. Castiglione was granted an award of 16,806 restricted units on April 22, 2013. Seventy-five percent (12,605 units) of this award are comprised of time vested units that vest in equal one-third increments over a 36-month period commencing on the Initial Date (i.e., approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the time vested units will be 100% vested on April 1, 2016, provided Mr. Castiglione has continuously provided services to us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. The remaining twenty-five percent (4,201 units) of this award are performance based units) subject to adjustment on the third anniversary of the grant, i.e., an increase (up to 225% of such performance based units) or a decrease (to 0% of such performance based units) based on a combination of QRE’s unit performance and relative total shareholder return.

⁽⁸⁾

Mr. Geiger was granted an award of 23,496 restricted units on July 25, 2012. Of this award, 19,340 units are time vested units that vest in equal one-third increments over a 36-month period (i.e., approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the time-vested units will be 100% vested on July 1, 2015), provided Mr. Geiger has continuously provided services to us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. The remaining 4,156 units of this award are performance based units subject to adjustment on the third anniversary of the grant, i.e., an increase (up to 225% of such performance based units) or a decrease (to 0% of such performance based units) based on a combination of QRE’s total unit performance and relative total shareholder return.

⁽⁹⁾

Mr. Geiger was granted an award of 16,806 restricted units on April 22, 2013. Seventy-five percent (12,605 units) of this award are comprised of time vested units that vest in equal one-third increments over a 36-month period commencing on the Initial Date (i.e., approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the time vested units will be 100% vested on April 1, 2016, provided Mr. Geiger has continuously provided services to us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. The remaining twenty-five percent (4,201 units) of this award are performance based units) subject to adjustment on the third anniversary of the grant, i.e., an increase (up to 225% of such performance based units) or a decrease (to 0% of such performance based units) based on a combination of QRE’s unit performance and relative total shareholder return.

⁽¹⁰⁾

Mr. Wagner was granted an award of 16,624 restricted units on July 25, 2012. Of this award, 12,468 units are time vested units that vest in equal one-third increments over a 36-month period (i.e., approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the time-vested units will be 100% vested on July 1, 2015), provided Mr. Wagner has continuously provided services to us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. The remaining 4,156 units of this award are performance based units subject to adjustment on the third anniversary of the grant, i.e., an increase (up to 225% of such performance based units) or a decrease (to 0% of such performance based units) based on a combination of QRE’s total unit performance and relative total shareholder return.

⁽¹¹⁾

Mr. Wagner was granted an award of 16,806 restricted units on April 22, 2013. Seventy-five percent (12,605 units) of this award are comprised of time vested units that vest in equal one-third increments over a 36-month period commencing on the Initial Date (i.e., approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the time vested units will be 100% vested on April 1, 2016, provided Mr. Wagner has continuously provided services to

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us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. The remaining twenty-five percent (4,201 units) of this award are performance based units) subject to adjustment on the third anniversary of the grant, i.e., an increase (up to 225% of such performance based units) or a decrease (to 0% of such performance based units) based on a combination of QRE’s unit performance and relative total shareholder return.

⁽¹²⁾

Mr. Roden was granted an award of 23,496 restricted units on July 25, 2012. Of this award, 19,340 units are time vested units that vest in equal one-third increments over a 36-month period commencing on July 1, 2013 (i.e., approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the time-vested units will be 100% vested on July 1, 2015, provided Mr. Roden has continuously provided services to us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. The remaining 4,156 units of this award are performance based units subject to adjustment on the third anniversary of the grant, i.e., an increase (up to 225% of such performance based units) or a decrease (to 0% of such performance based units) based on a combination of QRE’s total unit performance and relative total shareholder return.

⁽¹³⁾

Mr. Roden was granted an award of 18,056 restricted units on April 22, 2013. Seventy-five percent (13,542 units) of this award are comprised of time vested units that vest in equal one-third increments over a 36-month period commencing on the Initial Date (i.e., approximately 33.3% vest at each one-year anniversary of the Initial Date, so that the time vested units will be 100% vested on April 1, 2016, provided Mr. Roden has continuously provided services to us, our general partner or any of our respective affiliates without interruption, from the Initial Date through each applicable vesting date. The remaining twenty-five percent (4,514 units) of this award are performance based units) subject to adjustment on the third anniversary of the grant, i.e., an increase (up to 225% of such performance based units) or a decrease (to 0% of such performance based units) based on a combination of QRE’s unit performance and relative total shareholder return.

⁽¹⁴⁾

The market value of unvested restricted units listed in this column was calculated by multiplying the closing price of our common units on December 31, 2013, which was $17.12, by the number of restricted units outstanding.

⁽¹⁵⁾

The market value of unvested performance units listed in this column was calculated by multiplying the closing price of our common units on December 31, 2013, which was $17.12, by the number of performance units that would have been vested if the three year performance evaluation period for the 2012 and 2013 performance unit awards had ended on December 31, 2013 (the performance factor for the 2012 grants would have been 0.42 and for the 2013 grants 0.81) and adding the number of catch-up distributions that would have been paid on these units through December 31, 2013. If the performance evaluation period for the 2012 and 2013 performance award grants had ended on December 31, 2013, Messrs. Smith, Burgher, Castiglione, Geiger, Wagner and Roden would have been awarded 15,586, 8,476, 1,746, 1,746, 1,746 and 1,746 units respectively for the 2012 performance grant award and 33,750, 28,125, 3,403, 3,403, 3,403, and 3,656 units respectively for the 2013 performance grant award and Messrs. Smith, Burgher, Castiglione, Geiger, Wagner and Roden would have received catch-up distributions through December 31, 2013 of $70,897, $48,083, $7,572, $7,572, $7,572 and $7,820 respectively.

Option Exercises and Units Vested in 2013

The following table sets forth certain information with respect to restricted units vested during 2013.


Name	Number of Units Acquired on Vesting		Value Realized on Vesting (1)
Alan L. Smith	7,118	$	125,409
Cedric W. Burgher	27,352	$	462,361
Mark Castiglione	5,931	$	105,767
Paul W. Geiger, III	8,030	$	140,776
Patrick Wagner	4,156	$	73,852
Gregory S. Roden	9,780	$	169,756

⁽¹⁾

The dollar amount realized upon vesting of restricted units was calculated by multiplying the number of restricted units that vested by the market value of the underlying units on the vesting date. The values realized on vesting reported above represent the gross number of units received by the executives on vesting, prior to the withholding of any units for purposes of fulfilling federal and state income tax withholding obligations.

Pension Benefits

Currently, we do not, and we do not intend to, provide pension benefits to our named executive officers. Our general partner may change this policy in the future.

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Nonqualified Deferred Compensation Table

Currently, we do not, and we do not intend to, sponsor or adopt a nonqualified deferred compensation plan. Our general partner may change this policy in the future.

Potential Payments Upon Termination or Change in Control

As noted above, none of our named executive officers are parties to employment agreements, and none of them are covered by severance or change in control arrangements. Under the LTIP and the individual award agreements issued to our named executive officers in connection with the grant of the restricted unit awards, if a named executive officer ceases to provide services to us, our general partner and our respective affiliates by reason of the officer’s death or disability (as determined by us) or upon the occurrence of change of control (as defined below) while the named executive officer is providing services to us, our general partner or any of our respective affiliates, any unvested portion of the restricted units granted to the named executive officer will immediately become fully vested. For this purpose, a "change of control" will be deemed to have occurred (i) if any person or group, other than the partnership, our general partner or any of our respective affiliates, becomes the owner of more than 50% of the voting power of the voting securities of either the partnership or our general partner; (ii) if the limited partners of the partnership or our general partner approve, in one or a series of transactions, a plan of complete liquidation of the partnership or our general partner; (iii) upon the sale or other disposition by either the partnership or our general partner of all or substantially all of its assets, whether in a single or series of related transactions, to one or more parties (other than the partnership, our general partner or any of our respective affiliates); or (iv) if our general partner or an affiliate of the partnership or our general partner ceases to be the general partner of the partnership.

The following table quantifies our best estimates as to the amounts that each of our named executive officers would be entitled to receive upon a termination of employment as a result of his death or disability or upon a change of control, as applicable, assuming that such event occurred on December 31, 2013 and using our closing stock price on that date of $17.12. The number of units assumed to be paid out with respect to any performance-based restricted unit awards would be the target number granted. The precise amount that each of our named executive officers would receive cannot be determined with any certainty until an actual termination or change of control has occurred. Therefore, such amounts should be considered "forward-looking statements."


Name		Termination of Employment by Reason of Death or Disability (1)		Occurrence of a Change of Control (1)
Alan L. Smith	$	1,778,870	$	1,778,870
Cedric W. Burgher	$	2,356,790	$	2,356,790
Mark Castiglione	$	531,558	$	531,558
Paul W. Geiger, III	$	579,597	$	579,597
Patrick Wagner	$	501,170	$	501,170
Gregory S. Roden	$	600,997	$	600,997

⁽¹⁾

The value of the accelerated vesting of the restricted units granted to each named executive officer is based upon the closing price of our common units on December 31, 2013, $17.12, multiplied by the number of restricted units that would vest upon the occurrence of the event indicated. The number of awards each named executive officer held at the end of the 2013 year can be found above in the table titled “Outstanding Equity Awards at Fiscal 2013 Year-End.”

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation for their services as a director of our general partner. Directors who have a vested ownership interest in our general partner do not receive compensation for services provided to us as directors. We use a combination of cash and unit-based incentive compensation to attract and retain qualified candidates to serve on our general partner’s board of directors. In setting director compensation, we consider the significant amount of time that directors expend in fulfilling their duties to us as well as the skill level we require of members of the board. Each director who is not an officer or employee of our general partner or its affiliates receives an annual fee, paid in cash, and an award of fully vested LTIP units, as compensation for his or her services as a director to our general partner. The board has determined to award the independent directors with fully vested LTIP units, because these awards reflect compensation for services performed on behalf of the Partnership and our general partner and are not used for retention purposes. Directors do not receive additional compensation for serving on the audit, conflicts or compensation committees of the board of directors of our general partner or additional fees for each meeting

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attended. Each non-employee director is reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors and committees. Each director is also fully indemnified by us for actions associated with being a director to the full extent permitted under Delaware law.

Our general partner pays Mr. Wolf $200,000 in annual compensation for his service as a director of our general partner. In addition, both owners of our general partner pay Mr. Wolf up to 0.75% of each owner’s share of any management incentive fee paid to our general partner during the period of his service as a director of our general partner. We reimburse our general partner for the full amount of Mr. Wolf’s $200,000 in annual compensation for board services, and such costs are not included in the amounts reimbursed by our general partner for payments to Quantum Resources Management under the Services Agreement. Mr. Wolf’s compensation was initially established at the initial public offering and was reviewed and approved by the members of our general partner and reflects a subjective determination of the fees that should be paid to Mr. Wolf for his services provided as Chairman of the Board for our general partner, including participation in the evaluation of potential acquisitions and divestitures and communications with investors. The portion of any quarterly management incentive fee paid to Mr. Wolf by the owners of our general partner will not be an expense reimbursed by our general partner or us under the Services Agreement.

During 2013, our general partner paid each of Messrs. Powell, Thorington and Hebert $90,000 in cash and 6,667 units under the LTIP in annual compensation for their services as directors of our general partner. As the LTIP units awarded to the directors of our general partner’s board of directors are considered part of their compensation for services performed on our behalf in 2013 and not as a long term retention incentive, the LTIP units vested immediately upon issuance. No additional compensation or perquisites were awarded to the directors of our general partner other than the fees and LTIP units described above.

The table below includes compensation paid to our non-employee directors for their services during 2013. Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation for their services as a director of our general partner and, as such, are not included in the table below.


Name		Fees Earned or Paid in Cash		Unit Awards (1)		Option Awards		Non-Equity Incentive Plan Compensation		Nonqualified Deferred Compensation Earnings		All Other Compensation		Total
Donald E. Powell	$	90,000	$	120,006	$	-	$	-	$	-	$	-	$	210,006
Stephen A. Thorington	$	90,000	$	120,006	$	-	$	-	$	-	$	-	$	210,006
Richard K. Hebert	$	90,000	$	120,006	$	-	$	-	$	-	$	-	$	210,006
Donald D. Wolf	$	200,000	$	-	$	-	$	-	$	-	$	-	$	200,000

⁽¹⁾

Reflects the aggregate grant date fair value of unit awards granted under the LTIP calculated by multiplying the number of units granted to each director (6,667) by the closing price of our common units on the Initial Date ($18.00 with respect to the grants made to Messrs. Powell, Thorington and Hebert on April 22, 2013. These values were computed in accordance with FASB ASC Topic 718. See Part II, Item 8. Financial Statements and Supplementary Data – Note 15 – Equity-Based Compensation for fiscal 2013 for additional detail regarding assumptions underlying the value of these equity awards. LTIP equity awards for the independent directors were decided upon by the members of our general partner.

Compensation Practices as They Relate to Risk Management

We believe that our compensation programs do not encourage excessive and unnecessary risk taking by our named executive officers (or other employees). Short-term annual incentives are generally paid pursuant to discretionary bonuses, which enable the board of directors of our general partner to assess the actual behavior of our employees as it relates to risk taking in awarding bonus amounts. Further, our use of equity-based long-term incentive compensation serves our compensation program's goal of aligning the interests of executives and unitholders, thereby reducing the incentives to unnecessary risk taking. In addition, from a general risk management perspective, our policy is to conduct our commercial activities within predefined risk parameters that are closely monitored and are structured in a manner intended to control and minimize the potential for unwarranted risk-taking. We also routinely monitor and measure the execution and performance of our projects relative to expectations.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of December 31, 2013:


Plan Category	Number of issued and outstanding restricted units	Weighted-average exercise price of restricted units	Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans not approved by
unitholders Long-term incentive plan (1)	1,022,311	N/A	469,426

⁽¹⁾

Adopted by the board of directors of our general partner in connection with our initial public offering.

For a description of our equity compensation plan, please see the discussion under Part III, Item 11. Executive Compensation above.

Beneficial Ownership

As of March 2, 2014, the following table sets forth the beneficial ownership of our common, Class B, general partner and convertible preferred units that are owned by:

Each person beneficially owned more than 5% of the then outstanding units;

Each director and director nominee of our general partner;

Each named executive officer of our general partner; and

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


Name of Beneficial Owner (1)	Common Units to be Beneficially Owned (2), (4)	Percentage of Common Units to be Beneficially Owned	Class B Units to be Beneficially Owned	Percentage of Class B Units to be Beneficially Owned	Preferred Class C Units to be Beneficially Owned	Percentage of Preferred Class C Units to be Beneficially Owned
The Fund (4)	7,145,866	12.0%		0%	16,666,667	100.0%
Donald D. Wolf (18)	6,000	0.1%		0%	-	0.0%
Alan L. Smith (4), (9), (10), (11), (13), (19)	7,336,853	12.3%	6,133,558	100%	16,666,667	100.0%
John H. Campbell, Jr. (4), (9), (10), (11), (12), (19)	7,267,778	12.2%	6,133,558	100%	16,666,667	100.0%
Cedric W. Burgher (3)	201,170	0.1%		0%	-	0.0%
Mark Castiglione (6),	42,162	0.1%		0%	-	0.0%
Paul W. Geiger, III (7)	66,022	0.1%		0%	-	0.0%
Patrick Wagner (5)	33,293	0.1%		0%	-	0.0%
Gregory S. Roden (8)	55,089	0.1%		0%	-	0.0%
Toby R. Neugebauer (4), (9), (10), (19)	7,145,866	12.0%	6,133,558	100%	16,666,667	100.0%
S. Wil VanLoh, Jr. (4), (9), (10), (19)	7,145,866	12.0%	6,133,558	100%	16,666,667	100.0%
Donald E. Powell (14), (15)	33,240	0.1%		0%	-	0.0%
Stephen A. Thorington (14), (16)	44,540	0.1%		0%	-	0.0%
Richard K. Hebert (14), (17)	22,807	0.1%		0%	-	0.0%
All directors, director nominees and executive
officers of our general partner as a group	7,963,088	13.3%	6,133,558	100%	16,666,667	100.0%

⁽¹⁾

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

⁽²⁾

Includes common units that were awarded as LTIP units and common units purchased in the directed unit program at the closing of the IPO, and units purchased in the open market.

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⁽³⁾

Includes 5,000 units acquired by Mr. Burgher as part of the directed unit program; 75,000 units awarded to Mr. Burgher under the LTIP program upon the consummation of the IPO; 10,000 units awarded to Mr. Burgher under the LTIP program as part of his 2010 compensation; less 4,583 units deducted to cover withholding taxes occurring upon the vesting of 18,333 LTIP units on December 22, 2011; 47,237 units awarded to Mr. Burgher under the LTIP program as part of his 2012 compensation less 3,968 units deducted to cover withholding taxes occurring upon the vesting of 15,000 LTIP units on October 1, 2012; less 960 units deducted to cover withholding taxes occurring upon the vesting of 3,333 LTIP units on December 22, 2012; 69,444 units awarded to Mr. Burgher under the LTIP program as part of his 2013 compensation; and 3,600 common units purchased on the open market by Mr. Burgher on December 10, 2012. In addition, Mr. Burgher holds an indirect beneficial ownership interest in 400 common units held by members of his immediate family.

⁽⁴⁾

The 7,145,866 Subordinated Units were converted into common units on December 22, 2012.

⁽⁵⁾

Includes 16,624 common units awarded to Mr. Wagner under the LTIP program as part of his 2012 compensation; 16,806 common units awarded to Mr. Wagner under the LTIP program as part of his 2013 compensation; and 1,000 common units purchased on the open market by Mr. Wagner on May 23, 2012, less 1,137 units deducted to cover withholding taxes occurring upon the vesting of 4,156 units on July 1, 2013.

⁽⁶⁾

Includes 5,325 common units awarded to Mr. Castiglione under the LTIP program as part of his 2011 compensation; 1,000 common units acquired by Mr. Castiglione on December 22, 2010 as part of the directed unit program; 2,000 common units purchased on the open market by Mr. Castiglione on November 22, 2011; 2,500 common units purchased on the open market by Mr. Castiglione on May 14, 2012; and 16,624 common units awarded to Mr. Castiglione under the LTIP program as part of his 2012 compensation; and 16,806 common units awarded to Mr. Castiglione under the LTIP program as part of his 2013 compensation, less 470 units deducted to cover withholding taxes occurring upon the vesting of 1,775 LTIP units on November 1, 2012; less 1,137 units deducted to cover withholding taxes occurring upon the vesting of 4,156 LTIP units on July 1, 2013; less 486 units deducted to cover withholding taxes occurring upon the vesting of 1,775 LTIP units on November 1, 2013.

⁽⁷⁾

Includes 4,100 common units acquired by Mr. Geiger as a part of the directed unit program; 4,750 common units awarded to Mr. Geiger under the LTIP program upon the consummation of the IPO; 5,000 common units purchased on the open market by Mr. Geiger on May 16, 2012; 23,496 common units awarded to Mr. Geiger under the LTIP program as part of his 2012 compensation; 3,200 common units purchased on the open market by Mr. Geiger on November 14, 2012; 9,500 common units purchased on the open market by Mr. Geiger on December 13, 2012 (less 396 common units deducted to cover withholding taxes occurring upon the vesting of 1,583 LTIP units on December 22, 2011); 16,806 common units awarded to Mr. Geiger under the LTIP program as part of his 2013 compensation less 434 units deducted to cover withholding taxes occurring upon the vesting of 1,584 LTIP units on December 22, 2013.

⁽⁸⁾

Includes 10,000 common units awarded to Mr. Roden as part of his 2010 compensation; 2,000 common units purchased on the open market by Mr. Roden on June 2, 2011; 2,300 common units purchased on the open market by Mr. Roden on May 16, 2012; and 23,496 common units awarded to Mr. Roden under the LTIP program as part of his 2012 compensation; and 18,056 common units awarded to Mr. Roden under the LTIP program as part of his 2013 compensation; less 1,763 common units deducted to cover withholding taxes occurring upon the vesting of 6,446 LTIP units on July 1, 2013. In addition, Mr. Roden holds an indirect beneficial ownership interest in 1,000 common units owned by members of his immediate family.

⁽⁹⁾

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

QRA owns 6,533,194 Common Units and 15,066,277 Class C Preferred Units;

QRB owns 117,825 Common Units and 453,041 Class C Preferred Units;

QRC owns 209,150 Common Units and 478,604 Class C Preferred Units;

QAB owns 2,405 Common Units and 9,246 Class C Preferred Units;

QAC owns 4,268 Common Units and 16,412 Class C Preferred Units; and

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Black Diamond owns 279,024 Common Units and 643,087 Class C Preferred Units.

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

⁽¹⁰⁾

Our general partner, QRE GP, LLC is owned 50% by an entity controlled by Messrs. Neugebauer and VanLoh and 50% by an entity controlled by Messrs. Smith and Campbell. As indirect owners of our general partner, Messrs. Neugebauer, VanLoh, Smith and Campbell share in distributions made by us with respect to units held by our general partner in proportion to their respective ownership interests and with respect to payments made to our general partner relating to the management incentive fee. Messrs. Neugebauer, VanLoh, Smith and Campbell, by virtue of their ownership interest in our general partner, may be deemed to beneficially own the units held by our general partner.

⁽¹¹⁾

Includes 8,985 common units awarded to each Mr. Smith and Mr. Campbell under the LTIP program as part of their 2011 compensation.

⁽¹²⁾

Includes 30,000 common units purchased on the open market by Mr. Campbell on June 2, 2011; and 38,483 common units awarded to Mr. Campbell under the LTIP programs part of his 2012 compensation (28,862 of which are subject to a performance based adjustment to be determined at the end of three years based on a matrix that considers a combination of total unit returns and unit performance relative to the Partnership's peers); and 44, 444 common units awarded to Mr. Campbell under the LTIP program as part of his 2013 compensation (33,333 of which are subject to a performance based adjustment to be determined at the end of three years based on a matrix that considers a combination of total unit returns and unit performance relative to the Partnership's peers).

⁽¹³⁾

Includes 50,000 common units acquired by Mr. Smith as a part of the directed unit program; less 918 common units deducted to cover withholding taxes occurring upon the vesting of 2,995 LTIP units on March 9, 2012; and 49,478 common units awarded to Mr. Smith under the LTIP program as part of his compensation for 2012 (37,109 of which are subject to a performance based adjustment to be determined at the end of three years based on a matrix that considers a combination of total unit returns and unit performance relative to the Partnership's peers); and 55,556 common units awarded to Mr. Smith under the LTIP program as part of his compensation for 2013 (41,667 of which are subject to a performance based adjustment to be determined at the end of three years based on a matrix that considers a combination of total unit returns and unit performance relative to the Partnership’s peers); less 978 common units deducted to cover withholding taxes occurring upon the vesting of 2,995 LTIP units on March 9, 2013; less 1,136 common units deducted to cover withholding taxes occurring upon the vesting of 4,123 LTIP units on July 1, 2013.

⁽¹⁴⁾

Includes 3,750 fully vested units awarded to each Mr. Powell and Mr. Thorington under the LTIP program upon their appointment as directors of the general partner; and 4,123 fully vested units awarded to each Mr. Powell, Mr. Hebert, and Mr. Thorington under the LTIP program as part of their compensation for 2012; and 6,667 fully vested units awarded to each Mr. Powell, Mr. Hebert, and Mr. Thorington under the LTIP program as part of their compensation for 2013.

⁽¹⁵⁾

Includes 2,000 common units purchased on the open market by Mr. Powell on June 3, 2011; 1,082 common units purchased on the open market by Mr. Powell on November 17, 2011; 2,918 common units purchased on the open market by Mr. Powell on November 18, 2011; 1,000 common units purchased on the open market by Mr. Powell on November 21, 2011; 3,000 common units purchased on the open market by Mr. Powell on May 14, 2012; 4,000 common units purchased on the open market by Mr. Powell on May 15, 2012; 500 common units purchased on the open market by Mr. Powell on May 16, 2012; 2,000 common units purchased on the open market by Mr. Powell on May 18, 2012; 2,200 common units purchased on the open market by Mr. Powell on June 4, 2012.

⁽¹⁶⁾

Includes 20,000 common units acquired by Mr. Thorington under the directed unit program; 8,800 common units purchased on the open market by Mr. Thorington on May 14, 2012; and 1,200 common units purchased on the open market by Mr. Thorington on May 15, 2012.

⁽¹⁷⁾

Includes 1,817 fully vested common units awarded to Mr. Hebert under the LTIP program upon his appointment as a director of the general partner on July 1, 2011; 5,000 common units purchased on the open market by Mr. Hebert on November 17, 2011; 200 common units purchased on the open market by Mr. Hebert on December 6, 2011; and 5,000 common units purchased on the open market by Mr. Hebert on May 18, 2012.

⁽¹⁸⁾

Includes 6,000 common units purchased on the open market by Mr. Wolf on May 14, 2012.

110

⁽¹⁹⁾

The Class B Units are held by our general partner, QRE GP, LLC. Our general partner is owned 50% by an entity controlled by Messrs. Neugebauer and VanLoh and 50% by an entity controlled by Messrs. Smith and Campbell. As indirect owners of our general partner, Messrs. Neugebauer, VanLoh, Smith and Campbell share in the distributions of and from the Class B Units held by the general partner in proportion to their respective ownership interests. Messrs. Neugebauer, VanLoh, Smith and Campbell, by virtue of their ownership interest in our general partner, may be deemed to beneficially own the Class B Units of our general partner.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Ownership in Our General Partner by the Management of the Fund

As of December 31, 2013, entities controlled by affiliates of the Fund owned our general partner and a 29.2% limited partner interest in the Partnership from its ownership in our common units and preferred units. In addition, the general partner owns a 0.1% general partner interest in the Partnership, represented by 51,036 general partner units, and the general partner owns 6,133,558 Class B units.

On March 2, 2014, we completed a transaction related to our general partner interest pursuant to a Contribution Agreement, by and among the Partnership, the general partner, QR Holdings (QRE), LLC (“QRH”) and QR Energy Holdings, LLC (“QREH” and, together with QRH, the “QR Parties”), the former owners of our general partner, pursuant to which (i) the general partner reclassified its 0.1% general partner interest in the Partnership, formerly represented by 51,036 general partner units, in exchange for a non-economic general partner interest, (ii) the QR Parties contributed 100% of the limited liability company interests of the general partner to the Partnership, and (iii) the partnership agreement was amended, to, among other things, (a) cancel the management incentive fee and provide for the future issuance of up to 11.6 million Class B units, subject to certain tests, to the QR Parties and (b) provide for the election of all of the members of the board of directors of the general partner by our limited partners beginning in June 2015 (the “GP Buyout Transaction”).

Contracts with the Fund and Its Affiliates

Our general partner has entered into agreements with the Fund and its affiliates. The following is a description of those agreements.

Services Agreement

On December 22, 2010, in connection with the closing of the IPO, our general partner entered into a Services Agreement (the “Services Agreement”) with Quantum Resources Management, pursuant to which Quantum Resources Management will provide the administrative and acquisition advisory services necessary to allow our general partner to manage, operate and grow our business. Under the Services Agreement, from the closing of the IPO through December 31, 2012, 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. During the period from the closing of the IPO through December 31, 2010, and for the years ended December 31, 2011 and December 31, 2012, we incurred $0.1 million, $2.5 million and $7.3 million for the administrative services fee under the Services Agreement.

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 includes 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. The allocation methodology was developed with the assistance of a third-party consultant with extensive experience in this area. These fees are included in general and administrative expenses in our consolidated statement of operations. QRM has the discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.

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Omnibus Agreement

On December 22, 2010, in connection with the closing of the IPO, we entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among the Partnership, our general partner, OLLC, the Fund Entities, the Predecessor and QA Global.

Under the terms of the Omnibus Agreement, the Fund Entities will 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. The 70% threshold is a value-weighted determination made by the Fund Entities. Additionally, the Fund Entities will allow us to participate in at least 25% of any acquisition opportunity to the extent that it invests any of the remaining $113.2 million of its unfunded committed equity capital and so long as at least 70% of the allocated value of such acquisition opportunity is attributable to proved developed producing reserves. These contractual obligations will remain in effect for five years after the date of the Omnibus Agreement.

The Omnibus Agreement provides that the Fund Entities will indemnify us in connection with those assets contributed to us at the closing of the IPO against income taxes attributable to pre-closing operations as of the closing date of the IPO. The Fund indemnification obligation will terminate upon the expiration of the applicable statute of limitations with respect to income taxes.

Long–Term Incentive Awards / Plan

On February 3, 2014 we filed a definitive proxy statement on Form 14A, which provides information regarding a special meeting of limited partners to be held on March 10, 2014 to hold a unitholder vote on an amendment to our Long-Term Incentive Plan to increase the number of units under the plan by 3,000,000. See Part II, Item 8. Financial Statements and Supplementary Data See Note 22 – Subsequent Events.

On December 22, 2010, in connection with the closing of the IPO, the board of directors of the general partner adopted the QRE GP, LLC Long Term Incentive Plan (the “LTIP”) for employees, officers, consultants and directors and consultants of the general partner and those of its affiliates, including Quantum Resources Management, who perform services for us. The LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the LTIP is to provide additional incentive compensation to employees providing services to us and to align the economic interests of such employees with the interests of our unitholders. The LTIP limits the number of common units that may be delivered pursuant to awards under the plan to 1.8 million units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. As of December 31, 2013, 1,390,459 restricted unit awards had been granted under the LTIP.

Purchase and Sale Agreement

On December 28, 2012, the Fund sold the December 2012 Transferred Properties pursuant to a purchase and sale agreement by and among the Fund, the Partnership and OLLC in exchange for $28.6 million in cash, after customary purchase price adjustments, and the assumption of $115 million in debt. 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. As such, the value of the cash and assumed debt in excess of the net assets contributed by the Fund was deemed a $68.9 million distribution to the Predecessor and allocated pro rata to the general partner and existing limited partners.

On October 3, 2011 we completed the acquisition of the October 2011 Transferred Properties including certain oil and gas properties located in the Permian Basin, Ark-La-Tex and Mid-Continent areas from the Fund for an aggregate purchase price of $578.8 million, pursuant to the Purchase Agreement with an effective date of October 1, 2011.

In exchange for the October 2011 Transferred Properties, we assumed $227.0 million in debt from the Fund, which was repaid at closing and issued to the Fund 16,666,667 unregistered Class C Convertible Preferred Units (“Preferred Units”). The Preferred Units will receive a preferred quarterly distribution of $0.21 per Preferred Unit equal to a 4.0% annual coupon on the par value of $21.00, for the first three years following the date of issuance.

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After three years, the quarterly cash distribution will be equal to the greater of (a) $0.475 per Preferred Unit or (b) the cash distribution payable on each of our common units for such quarter. The Preferred Units are convertible, subject to certain limitations, into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment.

Registration Rights Agreement

In connection with the acquisition of the October 2011 Transferred Properties, on October 3, 2011, we entered into a Registration Rights Agreement with the Fund (the “Registration Rights Agreement”), which granted certain registration rights to the Fund, including rights to (a) cause the Partnership to file with the SEC up to five shelf registration statements under the Securities Act for the resale of the common units to be issued upon conversion of the Preferred Units, and in certain circumstances, the resale of the Preferred Units, and (b) participate in future underwritten public offerings of our common units.

The Fund may exercise its right to request that a shelf registration statement be filed any time after June 1, 2012. In addition, we agreed to use commercially reasonable efforts (a) to prepare and file a shelf registration statement within 60 days of receiving a request from the Fund and (b) to cause the shelf registration statement to be declared effective by the SEC no later than 180 days after its filing. The Registration Rights Agreement contains customary representations, warranties and covenants, and customary provisions regarding rights of indemnification between the parties with respect to certain applicable securities law liabilities.

Distributions of Available Cash to Our General Partner and Affiliates

We will generally make cash distributions to our common unitholders and Class B unitholders and general partner pro rata, including our general partner and our affiliates. As of December 31, 2013, our general partner and its affiliates held 7,145,866 common units, all of the preferred units and 51,036 general partner units. We distributed less than $0.1 million to our general partner during the year ended December 31, 2013. Preferred units receive a separate cash distribution in accordance with our Partnership Agreement.

General Partner Management Incentive Fee

Entities owned or controlled by the following individuals received the following Management Incentive Fees during 2013: (a) Alan Smith’s entity received $407,781, (b) John Campbell’s entity received $402,931, (c) Wil VanLoh’s entity received $823,633, and (d) Toby Neugebauer’s entity received $823,633. Each of the Management Incentive Fee amounts paid to Messrs, Smith, Campbell, VanLoh and Neugebauer reported above are net of Don Wolf’s share of the 2013 Management Incentive Fee of $40,944 and Cedric Burgher’s share of the 2013 Management Incentive Fee of $8,327. Don Wolf’s share was paid 37% by an entity controlled by Alan Smith and John Campbell and 63% by an entity controlled by Wil VanLoh and Toby Neugebauer. Cedric Burgher’s share was paid 50% by an entity controlled by Alan Smith and John Campbell and 50% by an entity controlled by Wil VanLoh and Toby Neugebauer.

Entities owned or controlled by the following individuals received the following Class B Distributions from Converted Management Incentive Fees during 2013: (a) Alan Smith’s entity received $796,884, (b) John Campbell’s entity received $775,944, (c) Wil VanLoh’s entity received $3,108,145, and (d) Toby Neugebauer’s entity received $3,108,145. Each of the distribution amounts paid to Messrs, Smith, Campbell, VanLoh and Neugebauer reported above are net of Don Wolf’s share of the 2013 Class B Distribution of $121,330. Don Wolf’s share was paid 26% by an entity controlled by Alan Smith and John Campbell and 74% by an entity controlled by Wil VanLoh and Toby Neugebauer.

The former owners of our general partner are entitled to receive an annual installment of Class B units with respect to any calendar year in which we pay a distribution of $0.4744 per unit with respect to each quarter, achieved a Distribution Coverage Ratio (as defined in our Partnership Agreement) for the year of at least 1.0 and achieve a Total Debt to EBITDAX (as defined in our Partnership Agreement) of no greater than 4.0 for each quarter during such year, unless any excess has been approved by the conflicts committee of our general partner.

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Review, Approval or Ratification of Transactions with Related Persons

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

Under our Code of Business Conduct and Ethics, any executive officer of our general partner is required to avoid conflicts of interest unless approved by the board of directors. The board of directors of our general partner has a standing conflicts committee comprised of at least one independent director and will determine whether to seek the approval of the conflicts committee in connection with future acquisitions of oil and natural gas properties from the Fund or its affiliates. In addition to acquisitions from the Fund or its affiliates, the board of directors of our general partner will also determine whether to seek conflicts committee approval to the extent we act jointly to acquire additional oil and natural gas properties with the Fund. In the case of any sale of equity or debt by us to an owner or affiliate of an owner of our general partner, our practice is to obtain the approval of the conflicts committee of the board of directors of our general partner for the transaction. The conflicts committee is entitled to hire its own financial and legal advisors in connection with any matters on which the board of directors of our general partner has sought the conflicts committee’s approval.

The Fund is free to offer properties to us on terms it deems acceptable, and the board of directors of our general partner (or the conflicts committee) is free to accept or reject any such offers, negotiating terms it deems acceptable to us. As a result, the board of directors of our general partner (or the conflicts committee) will decide, in its sole discretion, the appropriate value of any assets offered to us by the Fund. In so doing, we expect the board of directors (or the conflicts committee) will consider a number of factors in its determination of value, including, without limitation, production and reserve data, operating cost structure, current and projected cash flows, financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, reserve life, future drilling inventory and the weighting of the expected production between oil and natural gas. We expect that the Fund will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed purchase price of any assets it may offer to us in future periods. In addition to these factors, given that the Fund is our largest unitholder, the Fund may consider the potential positive impact on its underlying investment in us by offering properties to us at attractive purchase prices. Likewise, the Fund may consider the potential negative impact on its underlying investment in us if we are unable to acquire additional assets on favorable terms, including the negotiated purchase price.

Director Independence

The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner. For a discussion of the independence of the board of directors of our general partner, please see Part III, Item 10. Directors, Executive Officers and Corporate Governance – Committees of the Board of Directors and Independence Determination.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The audit committee of our general partner selected PricewaterhouseCoopers LLP, an independent registered public accounting firm, to audit our consolidated financial statements for the year ended December 31, 2013. The audit committee’s charter requires the audit committee to approve in advance all audit and non–audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit–related, tax and all other fees categories below with respect to this Annual Report on Form 10–K for the year ended December 31, 2013 were approved by the audit committee.

Fees paid and expected to be paid to PricewaterhouseCoopers LLP (“PwC”) are as follows:


		2013		2012		2011
Audit fees (1)	$	1,477	$	1,742	$	2,237
Audit - related fees (2)		36		169		-
Tax fees		320		329		241
Total fees paid to PwC	$	1,833	$	2,240	$	2,478

⁽¹⁾

Represents fees for professional services provided in connection with the audit of our annual financial statements, review of our quarterly financial statements and audits performed as part of our registration filings.

⁽²⁾

Represents audits of acquisition related financial statements and services in connection with, and comfort letters for, our senior notes offering and equity offerings.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

Our Consolidated Financial Statements are included under Part II, Item 8. of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” Page F-1 of this Annual Report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

(a)(3) Exhibits


Exhibit Number		Description
2.1	—	Purchase and Sale Agreement, dated as of December 28, 2012, by and among QRE Operating, LLC and Quantum Resources A1, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (Incorporated herein by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed January 3, 2013).
2.2	—	Purchase and Sale Agreement, dated as of June 27, 2013, by and among QRE Operating, LLC and an undisclosed private seller (Incorporated herein by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed July 2, 2013).
3.1	—	Certificate of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.2	—	First Amended and Restated Agreement of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
3.3	—	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, dated as of October 3, 2011 (Incorporated herein by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
3.4		Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, dated as of December 12, 2013 (Incorporated herein by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed December 17, 2013).
3.5	—	Certificate of Formation of QRE GP, LLC (Incorporated by reference to Exhibit 3.4 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.6	—	Amended and Restated Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
4.1+	—	Form of Restricted Unit Agreement under the QRE GP, LLC Long-Term Incentive Plan (Incorporated by reference to Exhibit 4.4 of the Partnership’s Registration Statement on Form S-8 (File No. 333-171333) filed on December 22, 2010).
4.2	—	Registration Rights Agreement, dated as of October 3, 2011, by and among QR Energy, LP, Quantum Resources A1, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (Incorporated herein by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
4.3	—	Indenture dated as of July 30, 2012 among QR Energy, LP, QRE Finance Corporation and QRE Operating, LLC and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on July 31, 2012.

116

4.4	—	Registration Rights Agreement dated as of July 30, 2012 among QR Energy, LP, QRE Finance Corporation, QRE Operating, LLC and Citigroup Global Markets Inc., Barclays Capital Inc., Credit Agricole Securities (USA) Inc., RBC Capital Markets, LLC, RBS Securities Inc. and Wells Fargo Securities, LLC, as representatives of the several initial purchasers (Incorporated by reference to Exhibit 4.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on July 31, 2012.
10.1	—	Stakeholders’ Agreement, by and among QR Energy, LP, Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP and QAC Carried WI, LP, and Black Diamond Resources, LLC, dated as of September 29, 2010 (Incorporated by reference to Exhibit 10.8 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
10.2	—	Omnibus Agreement by and among QR Energy, LP, QRE GP, LLC, Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources, C, LP, QAB Carried WI, LP, QAC Carried WI, LP, Black Diamond Resources, LLC, QA Holdings, LP and QA Global GP, LLC, dated December 22, 2010 (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
10.3	—	Services Agreement by and among QR Energy, LP, QRE GP, LLC, QRE Operating, LLC and Quantum Resources Management, LLC dated December 22, 2010 (Incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
10.4	—	Credit Agreement by and among QR Energy, LP, QRE GP, LLC, QRE Operating, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent, JPMorgan Chase Bank, N.A. as Syndication Agent, Royal Bank of Canada, The Royal Bank of Scotland plc and Toronto Dominion (New York) LLC, as Documentation Agents and the other lenders party thereto, dated as of December 22, 2010 (Incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
10.5	—	First Amendment to the Credit Agreement, dated as of October 3, 2011, by and among QR Energy, LP, QRE GP, LLC, QRE Operating, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent and the other lenders party thereto (Incorporated herein by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
10.6	—	Second Amendment to Credit Agreement dated as of March 16, 2012, by and among, QRE Operating, LLC, QR Energy, LP, QRE GP, LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on March 30, 2012).
10.7	—	Third Amendment to Credit Agreement dated April 11, 2012, by and among, QRE Operating LLC, QR Energy, LP, QRE GP, LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on April 16, 2012).
10.8	—	Fourth Amendment to Credit Agreement dated as of December 20, 2012, by and among, QRE Operating, LLC, QR Energy, LP, QRE GP, LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto (Incorporated herein by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed January 16, 2013).
10.9	—	Contribution, Conveyance and Assumption Agreement by and among QR Energy, LP, QRE GP, LLC, QRE Operating, LLC, 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 dated December 22, 2010 (Incorporated by reference to Exhibit 10.4 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
10.10+	—	QRE GP, LLC Long-Term Incentive Plan, adopted as of December 22, 2010 (Incorporated by reference to Exhibit 10.5 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).

117

10.11	—	Purchase and Sale Agreement, dated as of September 12, 2011, by and among QR Energy, LP, QRE Operating, LLC, Quantum Resources A1, LP, QAB Carried WI, LP, QAC Carried WI, LP, and Black Diamond Resources, LLC (Incorporated herein by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed September 12, 2011).
10.12	—	Purchase and Sale Agreement, dated as of March 19, 2012, by and among QRE Operating, LLC, Prize Petroleum, LLC and Prize Pipeline, LLC (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on March 22, 2012).
10.13	—	Purchase and Sale Agreement, dated as of October 26, 2012, by and among QRE Operating, LLC and an undisclosed private seller (Incorporated by reference to Exhibit 2.1 of the Partnership’s current Report on Form 8-K (File No. 001-35010) filed on November 1, 2012).
10.14	—	Amendment No. 1 to the Purchase and Sale Agreement, dated as of November 1, 2012, by and among QRE Operating, LLC and an undisclosed private seller (Incorporated by reference to Exhibit 2.2 of the Partnership’s current Report on Form 8-K (File No. 001-35010) filed on November 1, 2012).
10.15	—	Purchase and Sale Agreement, dated as of December 28, 2012, by and among QRE Operating, LLC and Quantum Resources A1, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (Incorporated by reference to Exhibit 2.1 of the Partnership’s current Report on Form 8-K (File No. 001-35010) filed on January 3, 2013).
10.16*	—	Fifth Amendment to Credit Agreement dated as of September 23, 2013, by and among, QRE Operating, LLC, QR Energy, LP, QRE GP, LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto.
21.1*	—	List of Subsidiaries of QR Energy, LP.
23.1*	—	Consent of PricewaterhouseCoopers LLP.
23.2*	—	Consent of Netherland, Sewell and Associates, Inc.
23.3*		Consent of Miller & Lents, Ltd.
31.1*	—	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
31.2*	—	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
32.1**	—	Certification of Chief Executive Officer Pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	—	Certification of Chief Financial Officer Pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	—	Report of Netherland, Sewell and Associates, Inc.

* Filed as an exhibit to this Annual Report on Form 10-K.

** Furnished as an exhibit to this Annual Report on Form 10-K.

*** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under those sections.

+ Management contracts or compensatory plans or arrangements

118

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

QR Energy, LP

(Registrant)

Date: March 3, 2014By: QRE GP, LLC, its general partner

By: /s/ Cedric W. Burgher

Cedric W. Burgher

Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 3, 2014.


Signature	Title (Position with QRE GP, LLC)	Date

/s/ Alan L Smith	Chief Executive Officer and Director	March 3, 2014
Alan L. Smith	(Principal Executive Officer)
/s/ John H. Campbell, Jr.	President, Chief Operating Officer and Director	March 3, 2014
John H. Campbell, Jr.
/s/ Cedric W. Burgher	Chief Financial Officer	March 3, 2014
Cedric W. Burgher	(Principal Financial Officer)
/s/ Gregory S. Roden	Sr. Vice President, Secretary and General Counsel	March 3, 2014
Gregory S. Roden
/s/ Lloyd V. DeLano	Chief Accounting Officer	March 3, 2014
Lloyd V. DeLano	(Principal Accounting Officer)
/s/ Richard K. Hebert	Director	March 3, 2014
Richard K. Hebert
/s/ Toby R. Neugebauer	Director	March 3, 2014
Toby R. Neugebauer
/s/ Donald E. Powell	Director	March 3, 2014
Donald E. Powell
/s/ Stephen A. Thorington	Director	March 3, 2014
Stephen A. Thorington
/s/ S. Wil VanLoh, Jr.	Director	March 3, 2014
S. Wil VanLoh, Jr.
/s/ Donald D. Wolf	Chairman of the Board	March 3, 2014
Donald D. Wolf

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INDEX TO FINANCIAL STATEMENTS

QR ENERGY, LP AUDITED CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2

Consolidated Balance Sheets as of December 31, 2013 and 2012	F-3

Consolidated Statements of Operations for the Years ended December 31, 2013, 2012 and 2011	F-4

Consolidated Statements of Comprehensive Income for the Years ended December 31, 2013, 2012, and 2011	F-5

Consolidated Statement of Changes in Partners' Capital for the Years ended December 31, 2013, 2012 and 2011	F-6

Consolidated Statements of Cash Flows for the Years ended December 31, 2013, 2012 and 2011	F-7

Notes to Consolidated Financial Statements	F-8

F–1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of QRE GP, LLC

and the Unitholders of QR Energy, LP

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, comprehensive income, changes in partners’ capital and cash flows present fairly, in all material respects, the financial position of QR Energy, LP and its subsidiaries (the “Partnership”) at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in Management's Annual Report on Internal Control over Financial Reporting appearing under Part II, Item 9A. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management's Annual Report on Internal Control over Financial Reporting management has excluded East Texas Salt Water Disposal Company from its assessment of internal control over financial reporting as of December 31, 2013 because it was acquired by the Partnership in a purchase business combination during 2013. We have also excluded East Texas Salt Water Disposal Company from our audit of internal control over financial reporting. East Texas Salt Water Disposal Company is a non-wholly owned subsidiary whose total assets and total revenues represent 2.2% and 2.2%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2013.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 3, 2014

F–2


QR ENERGY, LP
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit amounts)
		December 31,		December 31,
		2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	13,360	$	31,836
Accounts receivable		57,442		41,897
Due from affiliate		3,915		-
Due from general partner		-		165
Derivative instruments		27,485		45,522
Prepaid and other current assets		1,859		2,642
Total current assets		104,061		122,062
Noncurrent assets:
Oil and natural gas properties, using the full cost method of accounting
Evaluated		1,905,110		1,656,146
Unevaluated		4,320		11,500
Gross oil and natural gas properties		1,909,430		1,667,646
Other property, plant and equipment		14,114		-
Less accumulated depreciation, depletion and amortization		(318,561)		(203,377)
Total oil and natural gas properties and other property, plant and equipment, net		1,604,983		1,464,269
Derivative instruments		62,131		76,621
Other assets		44,752		23,575
Total noncurrent assets		1,711,866		1,564,465
Total assets	$	1,815,927	$	1,686,527
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Current portion of asset retirement obligations	$	4,310	$	1,426
Derivative instruments		11,233		8,727
Accrued and other liabilities		79,045		46,284
Total current liabilities		94,588		56,437
Noncurrent liabilities:
Long-term debt		911,593		766,076
Derivative instruments		6,251		16,993
Asset retirement obligations		151,011		125,565
Deferred taxes		2,114		102
Other liabilities		12,911		6,790
Total noncurrent liabilities		1,083,880		915,526
Commitments and contingencies (See Note 11)
Partners' capital:
Class C convertible preferred unitholders (16,666,667 units issued and outstanding as of December 31, 2013 and 2012)		388,621		373,068
General partner (51,036 units issued and outstanding as of December 31, 2013 and 2012)		614		710
Class B unitholders (6,133,558 and zero units issued and outstanding as of December 31, 2013 and 2012)		-		-
Public common unitholders (51,483,263 and 51,299,278 units issued and outstanding as of December 31, 2013 and 2012)		313,302		403,757
Affiliated common unitholders (7,145,866 units issued and outstanding as of December 31, 2013 and 2012)		(76,371)		(62,971)
Accumulated other comprehensive income		2,744		-
Total QR Energy, LP Partners' capital		628,910		714,564
Noncontrolling interest		8,549		-
Total partners' capital		637,459		714,564
Total liabilities and partners' capital	$	1,815,927	$	1,686,527

See accompanying notes to the consolidated financial statements

F–3


QR ENERGY, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)


	Year Ended December 31,
	2013		2012		2011
Revenues:
Oil and natural gas sales	$	446,801	$	368,189	$	356,579
Disposal, processing and other		8,828		3,809		4,325
Total revenues		455,629		371,998		360,904
Operating Expenses:
Production expenses		174,101		143,938		132,227
Disposal and related operating expenses		6,597		-		-
Depreciation, depletion and amortization		115,184		105,796		94,993
Accretion of asset retirement obligations		7,456		5,648		4,593
General and administrative		41,901		42,275		37,315
Acquisition and transaction costs		1,487		4,000		-
Total operating expenses		346,726		301,657		269,128
Operating income (loss)		108,903		70,341		91,776
Other income (expense):
Gain (loss) on commodity derivative contracts, net		(1,217)		53,071		47,860
Interest expense, net		(48,000)		(43,133)		(50,491)
Other income (expense), net		1,589		-		-
Total other income (expense), net		(47,628)		9,938		(2,631)
Income (loss) before income taxes		61,275		80,279		89,145
Income tax (expense) benefit, net		353		(528)		(850)
Net income (loss)		61,628		79,751		88,295
Less: Net income (loss) attributable to noncontrolling interest		663		-		-
Net income (loss) attributable to QR Energy, LP	$	60,965	$	79,751	$	88,295
Net Income (loss) attributable to QR Energy, LP per limited partner unit:
Common unitholders' (basic)	$	0.26	$	0.19	$	0.10
Common unitholders' (diluted)		0.26		0.19		0.10
Subordinated unitholders' (basic and diluted)		-		0.11		0.10
Weighted average number of limited partner units outstanding:
Common units (basic)		58,524		35,132		28,728
Common units (dilutive)		58,524		35,282		28,728
Subordinated units (basic and diluted)		-		6,970		7,146

See accompanying notes to the consolidated financial statements

F–4


QR ENERGY, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)

		Year ended December 31,
		2013	2012		2011

Net income	$	61,628	$	79,751	$	88,295

Other comprehensive income, net of tax:
Reclassification adjustment for available-for-sale securities		(18)		-		-
Change in fair value on available-for-sale securities (1)		631		-		-
Pension and postretirement benefits:
Actuarial gain (2)		4,061		-		-
Total other comprehensive income		4,674		-		-
Total comprehensive income		66,302		79,751		88,295
Less: Comprehensive income attributable to noncontrolling interest		2,593		-		-

Comprehensive income attributable to QR Energy, LP	$	63,709	$	79,751	$	88,295

(1) Net of income taxes of $223 for the year ended December 31, 2013.
(2) Net of income taxes of $2,093 for the year ended December 31, 2013.


See accompanying notes to the consolidated financial statements

F–5


QR ENERGY, LP
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
(In thousands)

			Class C												Accumulated		Total
			Convertible						Limited Partners						Other		QR Energy, LP		Non-		Total
	Predecessor's		Preferred		General		Class B		Public		Affiliated				Comprehensive		Partners'		Controlling		Partners'
	Capital		Unitholders		Partner		Unitholders		Common		Common		Subordinated		Income		Capital		Interest		Capital
Balances - December 31, 2010	$	129,089	$	-	$	708	$	-	$	276,723	$	(48,898)	$	(30,928)	$	-	$	326,694	$	-	$	326,694
Proceeds from over-allotment		-		-		-		-		41,963		-		-		-		41,963		-		41,963
Distribution to the Fund		-		-		-		-		-		(25,727)		(16,273)		-		(42,000)		-		(42,000)
Distributions to the Predecessor		(25,507)		-		-		-		-		-		-		-		(25,507)		-		(25,507)
Other contributions from affiliates		17,357		-		-		-		-		12,366		7,822		-		37,545		-		37,545
Recognition of unit-based awards		-		-		-		-		1,351		-		-		-		1,351		-		1,351
Reduction in units to cover individuals' tax withholding		-		-		-		-		(215)		-		-		-		(215)		-		(215)
Distributions to unitholders		-		(3,424)		(63)		-		(30,673)		(19,854)		(12,557)		-		(66,571)		-		(66,571)
Book value of October 2011 Transferred Properties contributed by the Predecessor		(249,331)		-		-		-		-		-		-		-		(249,331)		-		(249,331)
Fair value of Preferred Units issued to the Fund		-		354,500		-		-		-		-		-		-		354,500		-		354,500
Fair value of Preferred Units in excess of net assets received from the Fund		-		-		(102)		-		(49,491)		(32,380)		(20,481)		-		(102,454)		-		(102,454)
Amortization of discount on increasing rate distributions		-		3,638		-		-		-		-		-		-		3,638		-		3,638
Noncash distribution to preferred unitholders		-		(3,638)		-		-		-		-		-		-		(3,638)		-		(3,638)
Management incentive fee earned		-		-		(1,572)		-		-		-		-		-		(1,572)		-		(1,572)
Net income		76,249		7,062		1,575		-		1,648		1,079		682		-		88,295		-		88,295
Balances - December 31, 2011	$	(52,143)	$	358,138	$	546	$	-	$	241,306	$	(113,414)	$	(71,735)	$	-	$	362,698	$	-	$	362,698
Distributions to the Predecessor		(37,270)		-		-		-		-		-		-		-		(37,270)		-		(37,270)
Proceeds from unit offerings		-		-		272		-		376,938		-		-		-		377,210		-		377,210
Book value of December 2012 Transferred Properties contributed by the Predecessor		45,578		-		-		-		-		-		-		-		45,578		-		45,578
Other contributions from affiliates		6,485		-		-		-		-		4,985		26,606		-		38,076		-		38,076
Recognition of unit-based awards		-		-		-		-		3,252		-		-		-		3,252		-		3,252
Reduction in units to cover individuals' tax withholding		-		-		-		-		(322)		-		-		-		(322)		-		(322)
Distributions to unitholders		-		(14,000)		(60)		-		(55,005)		-		(10,362)		-		(79,427)		-		(79,427)
Conversion of subordinated units		-		-		-		-		-		(53,122)		53,122		-		-		-		-
Amortization of discount on increasing rate distributions		-		14,930		-		-		-		-		-		-		14,930		-		14,930
Noncash distribution to preferred unitholders		-		(14,930)		-		-		-		-		-		-		(14,930)		-		(14,930)
Affiliated unit sale to public		-		-		-		-		(113,325)		113,325		-		-		-		-		-
Consideration paid in excess of the December 2012 Transferred Properties received from the Fund		-		-		(59)		-		(60,390)		(8,412)		-		-		(68,861)		-		(68,861)
Management incentive fee earned		-		-		(6,121)		-		-		-		-		-		(6,121)		-		(6,121)
Net income		37,350		28,930		6,132		-		11,303		(6,333)		2,369		-		79,751		-		79,751
Balances - December 31, 2012	$	-	$	373,068	$	710	$	-	$	403,757	$	(62,971)	$	-	$	-	$	714,564	$	-	$	714,564
Recognition of unit-based awards		-		-		-		-		6,880		-		-		-		6,880		-		6,880
Reduction in units to cover individuals' tax withholding										(583)								(583)				(583)
Unit issuance costs		-		-		-		-		(76)		-		-		-		(76)		-		(76)
Distribution to unitholders		-		(14,000)		(108)		(12,839)		(110,184)		(15,096)		-		-		(152,227)		-		(152,227)
Amortization of discount on increasing rate distributions		-		15,553		-		-		-		-		-		-		15,553		-		15,553
Noncash distribution to preferred unitholders		-		(15,553)		-		-		-		-		-		-		(15,553)		-		(15,553)
Management incentive fee earned		-		-		(3,357)		-		-		-		-		-		(3,357)		-		(3,357)
Noncontrolling interest in connection with acquisition		-		-		-		-		-		-		-		-		-		5,956		5,956
Other		-		-		1		-		836		(837)		-		-		-		-		-
Other comprehensive income, net of tax		-		-		-		-		-		-		-		2,744		2,744		1,930		4,674
Net income		-		29,553		3,368		12,839		12,672		2,533		-		-		60,965		663		61,628
Balances - December 31, 2013	$	-	$	388,621	$	614	$	-	$	313,302	$	(76,371)	$	-	$	2,744	$	628,910	$	8,549	$	637,459




See accompanying notes to the consolidated financial statements

F–6


QR ENERGY, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


	Year Ended December 31,
	2013		2012		2011
Cash flows from operating activities:
Net income (loss) (1)	$	61,628	$	79,751	$	88,295
Adjustments to reconcile net income (loss) to net cash provided by (used in)
operating activities:
Depreciation, depletion and amortization		115,184		105,796		94,993
Accretion of asset retirement obligations		7,456		5,648		4,593
Amortization of deferred financing costs		2,424		2,898		2,101
Recognition of unit-based awards		6,880		3,252		1,351
General and administrative expense contributed by affiliates		-		38,076		34,721
Loss (gain) on derivative contracts, net		4,130		(42,850)		(18,434)
Cash received (paid) on settlement of derivative contracts		20,161		27,863		(76,565)
Deferred income (benefit) tax expense		(304)		372		849
Other items		2,935		2,075		357
Changes in operating assets and liabilities:
Accounts receivable and other assets		(21,762)		(8,531)		(29,386)
Accounts payable and other liabilities		3,413		12,800		9,682
Net cash provided by operating activities		202,145		227,150		112,557
Cash flows from investing activities:
Additions to oil and natural gas properties		(88,247)		(127,352)		(70,426)
Acquisitions, net of cash acquired		(128,234)		(468,009)		(3,044)
Proceeds from sale of oil and natural gas properties		-		3,082		1,327
Proceeds from sale of available-for-sale securities		8,535		-		-
Purchases of available-for-sale securities		(10,249)		-		-
Net cash used in investing activities		(218,195)		(592,279)		(72,143)
Cash flows from financing activities:
Proceeds from unit offering, net of offering costs		87		376,938		41,963
Proceeds from senior note offering, net of underwriter discount		-		295,860		-
Distributions to the Fund		-		-		(42,000)
Proceeds from issuance of units to the general partner		-		115		715
Management incentive fee paid to the general partner		(3,357)		(7,692)		-
Distributions to unitholders		(141,582)		(96,472)		(46,026)
Contributions from (distributions to) the Predecessor		-		(34,973)		(25,507)
Proceeds from bank borrowings		180,000		476,500		275,000
Repayments on bank borrowings		(35,000)		(506,500)		-
Repayment of debt assumed from the Fund		-		(115,000)		(227,000)
Units withheld for employee payroll tax obligation		(583)		(322)		-
Deferred financing costs		(1,991)		(8,922)		(2,321)
Net cash provided by (used in) financing activities		(2,426)		379,532		(25,176)
Increase (decrease) in cash		(18,476)		14,403		15,238
Cash and cash equivalents at beginning of period		31,836		17,433		2,195
Cash and cash equivalents at end of period	$	13,360	$	31,836	$	17,433

(1) Includes net income attributable to noncontrolling interest.

See accompanying notes to the consolidated financial statements

F–7

QR Energy, LP

Notes to Consolidated Financial Statements

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

NOTE 1 — ORGANIZATION AND OPERATIONS

QR Energy, LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed on September 20, 2010 to acquire oil and gas assets from our affiliated entity, QA Holdings, LP (the “Predecessor”) and other third party entities in order to enhance and exploit oil and gas properties. We currently have oil and gas related properties in Alabama, Arkansas, Florida, Kansas, Louisiana, Michigan, New Mexico, Oklahoma and Texas. Certain of the Predecessor’s subsidiaries (collectively known as the “Fund”) include Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC.

Our general partner is QRE GP, LLC (or “QRE GP”). We conduct our operations through our 100% owned subsidiary QRE Operating, LLC (“OLLC”). Our 100% owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities. In connection with our acquisition of certain East Texas oil properties (see Note 4 – Acquisitions), we acquired a controlling interest in East Texas Saltwater Disposal Company (“ETSWDC”), a privately held Texas corporation. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil produced in certain East Texas oilfields.

Quantum Resources Management, LLC (“QRM”), a subsidiary of QA Holdings, LP, provides management and operational services for us and the Fund. In accordance with the Services Agreement (the “Services Agreement”) between us, QRE GP and QRM, beginning on January 1, 2013, QRM is entitled to the reimbursement of general and administrative charges from us based on the allocation of charges between the Fund and us. Prior to January 1, 2013, the Partnership was required to pay an administrative services fee equal to 3.5% of Adjusted EBITDA, as defined in the Services Agreement. Refer to Note 2 – Summary of Significant Accounting Policies for details on the allocation of general and administrative expenses beginning on January 1, 2013.

As of December 31, 2013, our ownership structure comprised a 0.1% general partner interest, a 7.5% limited partner interest in us represented by 6,133,558 Class B units held by QRE GP, a 29.2% limited partner interest held by the Fund, comprised of common units and all of our preferred units, and a 63.2% limited partner interest held by the public unitholders. On February 22, 2013, in accordance with our partnership agreement, our general partner elected to convert 80% of their fourth quarter 2012 management incentive fee and, on March 4, 2013, received 6,133,558 Class B units which were issued and outstanding upon conversion.

On March 2, 2014 we completed a transaction related to our general partner interest pursuant to a Contribution Agreement. See Note 22 – Subsequent Events for more information.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2013 and 2012. These financial statements also include the results of our operations, our changes in comprehensive income, changes in partners’ capital, and cash flows for the years ended December 31, 2013, 2012, and 2011. These consolidated financial statements include all of our wholly-owned subsidiaries and investments we are deemed to have control.

These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. When necessary, certain reclassifications have been made to the previous years to conform to the 2013 presentation.

Use of Estimates

F–8

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates particularly significant to the financial statements include the following:

Estimates of our reserves of oil, natural gas and natural gas liquids (“NGL”);

Future cash flows from oil and gas properties;

Depreciation, depletion and amortization expense;

Asset retirement obligations;

Pension and postretirement obligations;

Fair values of derivative instruments and investments;

Unit based compensation;

Fair values of assets acquired and liabilities assumed from business combinations; and

Natural gas imbalances.

As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuous changes in the economic environment will be reflected in the financial statements in future periods.

There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including future costs to dismantle, dispose and restore our properties. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. Our cash and cash equivalents consist of cash in banks and investments in money market accounts. The majority of cash and cash equivalents are maintained with a major financial institution in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We use the specific identification method of providing allowances for doubtful accounts. As of December 31, 2013 and 2012, the allowance for doubtful accounts was not material.

Property and Equipment

Oil and Natural Gas Properties. We account for our oil and natural gas exploration and development activities under the full cost method of accounting. Under this method, all costs associated with property exploration and development (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and direct overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities are capitalized. Gains and losses are not recognized on the sale of disposition of oil and gas properties unless the adjustment would significantly alter the relationship between capitalized costs and proved oil and gas reserves attributable to a cost center. Under full cost accounting, cost centers are established on a country-by-country basis. We have one cost center as we operate exclusively in the United States. Expenditures for maintenance and repairs are charged to expense in the period incurred, with the exception of workovers resulting in an increase in proved reserves which are capitalized.

F–9

Ceiling Test. Pursuant to full cost accounting rules, we must perform a ceiling test at the end of each quarter related to our proved oil and natural gas properties. The ceiling test provides that capitalized costs less related accumulated depreciation, depletion and amortization may not exceed an amount equal to (1) the present value of future net revenue from estimated production of proved oil and natural gas reserves, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, discounted at 10% per annum; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any. If the net capitalized costs exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs.

The ceiling calculation utilizes prices calculated as a twelve-month average price using first day of the month prices and costs in effect as of the last day of the period are held constant. The prices used are adjusted for basis or location differentials, product quality, energy content and transportation fees. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date.

There were no write-downs required by us during the years ended December 31, 2013, 2012, and 2011. Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that we could incur a write-down.

Depletion. The provision for depletion of proved oil and natural gas properties is calculated on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The Partnership and the Predecessor calculate depletion on a quarterly basis.

Unevaluated Properties. In connection with the Prize Acquisition, the 2013 East Texas Acquisition and the 2012 East Texas Acquisition, we acquired unevaluated properties which are not being depleted pending determination of the existence of proved reserves. Unevaluated properties are assessed quarterly to ascertain whether there is a probability of obtaining proved reserves in the future. When it is determined that these properties have been promoted to a proved reserve category or there is no longer any probability of obtaining proved reserves from the properties, the costs associated with these properties are transferred into the amortization base to be included in the depletion calculation and subject to the ceiling test. Unevaluated properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geological data obtained relating to the properties. Where it is not practical to assess properties individually as their costs are not individually significant, such properties are grouped for purposes of the periodic assessment.

Other Property, Plant and Equipment. Other property, plant and equipment consists of property and equipment related to the disposal of saltwater in our East Texas fields and are held at cost and depreciated on a straight-line basis over 5 to 25 years.

Transactions Between Entities Under Common Control

From time to time we enter into transactions whereby we receive a transfer of certain oil and natural gas assets from our Predecessor with units issued or cash paid us. We account for the net assets received using the historical book value of the Predecessor as these are transactions between entities under common control. Our historical financial statements have been revised to include the results attributable to the assets contributed from the Predecessor as if we owned such assets for all periods presented by the Partnership.

Oil and Natural Gas Properties Received. The historical book value of oil and natural gas properties received from the Predecessor is determined using the ratio of the value, based on a discounted cash flow model, of the reserves contributed to the total value of the Predecessor’s oil and gas reserves at the beginning of the earliest revised period. This ratio is then applied to the book value of oil and gas properties to determine the beginning book value of the contributed properties. This reserve ratio was also applied to determine the book value of any additions made to the assets contributed by the Predecessor during the revision period.

Long-Term Debt Assumed. The historical book value and related activity of long-term debt assumed from the Predecessor was determined by using the effective date amount of debt assumed per the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. The Partnership’s financial statements include the

F–10

beginning IPO Closing Date balance, borrowings and repayments of the assumed debt to properly reflect these debt transactions as if the Partnership owned the October 2011 Transferred Properties and the December 2012 Transferred Properties for the periods presented by the Partnership.

Asset Retirement Obligations Received. The historical book value and related activity of asset retirement obligations received from the Predecessor was determined by using the specific obligations related to the properties listed in the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. These asset retirement balances as of the effective date of the purchase agreements and all related previous activity dating back to the IPO Closing Date are included in the Partnership’s financial statements.

Other Assets Received. The historical book value and related activity of other assets received from the Predecessor was determined by using the assets listed in the December 2012 Purchase Agreement. The balances of these assets as of the effective date of the December 2012 Purchase Agreement and all related previous activity dating back to the IPO Closing Date are included in the Partnership’s financial statements.

Derivative Instruments Received. The historical book value and related activity of commodity and interest rate derivative instruments received from the Predecessor was determined by using the instruments listed in the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. The balances of these derivative instruments as of the effective date of the purchase agreements and related previous unrealized gains and losses and modifications dating back to the IPO Closing Date are included in the Partnership’s financial statements.

Other Liabilities Assumed. The historical book value and related activity of other liabilities assumed including natural gas imbalances received from the Predecessor was determined by using the specific obligations related to the properties listed in the October 2011 Purchase Agreement. The balances of these obligations as of the effective date of the October 2011 Purchase Agreement and all related previous activity dating back to the IPO Closing Date are included in the Partnership’s financial statements.

Oil and Natural Gas Revenues and Expenses. Oil and natural gas revenues and expenses related to the October 2011Transferred Properties and the December 2012 Transferred Properties were determined based on operating activity for the specific properties listed in the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. All oil and natural gas revenues and expense activity are included in the Partnership’s financial statements dating back to the IPO Closing Date.

General and Administrative Expenses. The general and administrative expense attributable to the October 2011Transferred Properties and the December 2012 Transferred Properties was determined by the ratio of production for the October 2011 Transferred Properties and the December 2012 Transferred Properties to the total Predecessor’s production. This ratio was applied to the specific properties listed in the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. All general and administrative expense identified is included in the Partnership’s financial statements dating back to the IPO Closing Date.

Business Combinations

Oil and Natural Gas Reserve Quantities

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. Our independent reserve engineers also adhere to the SEC definitions when preparing their reserve reports.

F–11

Investments

Investments consist of debt and equity securities, all of which are classified as available-for-sale and stated at fair value on our consolidated balance sheet. Accordingly, unrecognized changes in fair value and the related deferred tax effect are excluded from earnings and reported as a separate component within our consolidated statement of other comprehensive income. Changes in fair value of securities sold are computed based on the specific identification of the securities sold and reclassified from other comprehensive income into earnings in the period sold.

Pensions and Other Postretirement Benefits

We recognize the overfunded or underfunded status of the pension and postretirement benefit plans as either assets or liabilities on our consolidated balance sheet. A plan’s funded status is the difference between the fair value of the plan assets and the plan’s benefit obligation. The plan’s benefit obligation is based on estimates using management’s best estimate and judgments which includes independent actuarial service assumptions to determine the plan obligation. We record the plan’s cost and income – unrecognized losses and gains, unrecognized prior service costs and credits and any transition obligations, if any – in our statement of other comprehensive income until they are amortized into earnings as a component of benefit costs.

Asset Retirement Obligations

We have significant obligations to plug and abandon oil, natural gas and saltwater disposal wells and related equipment at the end of oil and natural gas production or saltwater disposal operations. We incur these liabilities upon acquiring or drilling a well. GAAP requires entities to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depleted as a component of the full cost pool. The fair values of additions to the ARO liability are estimated using present value techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) inflation factors; and (iv) a credit-adjusted risk free rate. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance. Upon settlement of liabilities related to our oil and natural gas properties, we adjust the full cost pool to the extent the actual costs differ from the recorded liability. Upon settlement of liabilities related to our other property, plant and equipment, we record a gain or loss in earnings to the extent the actual costs differ from the recorded liability. See Note 8 – Asset Retirement Obligation.

Derivatives

We monitor our exposure to various business risks, including commodity price risks and interest rate risks, and use derivatives to manage the impact of certain of these risks. Our policies do not permit the use of derivatives for speculative purposes. We use commodity derivatives for the purpose of mitigating risk resulting from fluctuations in the market price of oil and natural gas and interest rate derivatives for the purpose of mitigating risk resulting from fluctuations in interest rates.

We have elected not to designate our derivatives as hedging instruments. Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Gains and losses on derivatives are reported as nonoperating income or expense on the statements of operations in “Gain (loss) on commodity derivative contracts, net.” Gains and losses on derivatives include the cash settlement of derivative contracts and the non-cash change in fair value of the derivative instruments. See Note 6 – Fair Value Measurements and Note 7 – Derivative Activities.

Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The credit worthiness of the counterparties is subject to continual review. We believe the risk of nonperformance by our counterparties is low. Full performance is anticipated, and we have no past-due balances from our counterparties. In addition, although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have properly presented all asset and liability positions without netting. See Note 7 – Derivative Activities.

F–12

Deferred Financing Costs

Costs incurred in connection with the execution or modification of our debt arrangements are capitalized and charged to interest expense over the term of the debt instrument. The net capitalized costs associated with our revolver are adjusted for downward revisions to the borrowing base.

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt. The carrying amounts of our financial instruments other than derivatives and long-term debt approximate fair value because of the short-term nature of the items. Derivatives are recorded at fair value. The carrying value of our debt under the Revolving Credit Facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. The Senior Notes are recorded at historical cost. See Note 6 – Fair Value Measurements.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. A process is used to determine when expenses should be recorded for these contingencies and the estimate of reasonable amounts for the accrual. We closely monitor known and potential legal, environmental and other contingencies, and periodically determine when we should record losses for these items based on information available. Based on management’s assessment, no contingent liabilities have been recorded by the Partnership as of December 31, 2013 or 2012, with the exception of an environmental liability acquired in the Prize Acquisition. See Note 11 – Commitments and Contingencies for further details.

Concentrations of Credit and Market Risk

Credit risk

Financial instruments which potentially subject us to credit risk consist principally of temporary cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at time, may exceed the federally insured limits. We have not experienced any significant losses from such investments. We attempt to limit the amount of credit exposure to any one financial institution or company. Procedures that may be used to manage credit exposure include credit approvals, credit limits and terms, letters of credit, prepayments and rights of offset.

Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry. We have not experienced any material credit losses on such sales in the past. See Note 17 – Significant Customers for further details.

Market Risk

Our activities primarily consist of acquiring, owning, enhancing and producing oil and gas properties. The future results of our operations, cash flows and financial condition may be affected by changes in the market price of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond our control, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment and, other regional and political events, none of which can be predicted with certainty.

Preferred Units

Our Preferred Units are convertible by the preferred unitholders and us under certain circumstances into common units. These conversion features result in settlement in common units and the option to convert is clearly and closely related to the units. These units are also not redeemable in cash. As such, we have classified the Preferred Units as permanent equity.

F–13

The Preferred Units have a liquidation preference equal to $21.00 per unit outstanding and any cumulative distributions in arrears.

We recorded the Preferred Units at their fair value of $21.27 per unit or $354.5 million in partners’ capital. Because the Preferred Units include stated distribution rates which increase over time, from a rate considered below market, we will amortize an incremental amount which together with the stated rate for the period results in a constant distribution rate in accordance with GAAP. We determined the present value of the incremental distributions of $46.2 million will be amortized over the period preceding the perpetual dividend rate using an effective interest rate of 8.1%. The amortization will increase the carrying value of the Preferred Units with an offsetting noncash distribution reducing the general partner’s and limited partners’ capital accounts on a pro rata basis. These distributions will be included in preferred distributions in our calculation of net income applicable to limited partners and basic and diluted net income per unit.

There was no beneficial conversion feature as our common units were trading below the $21.27 per unit fair value of the Preferred Units as of December 31, 2013.

Revenue Recognition

Revenues from oil, natural gas and NGL sales are recognized upon delivery and passage of title when evidence of arrangement exists and collectability is reasonably assured. Gas imbalances are recognized using the sales method, net of any royalty interests or other profit interests in the produced product. Revenues from natural gas production may result in more or less than our pro rata share of production from certain wells. Under the sales method for natural gas sales and natural gas imbalances, when our sales volumes exceed our entitled share and the overproduced balance exceeds our share of remaining estimated proved natural gas reserves for a given property, we record a liability. See Note 16 – Accrued and Other Liabilities.

General and Administrative Expenses

The Partnership shares general and administrative expenses with other affiliates who also receive management and accounting services from QRM under a Services Agreement, as defined in Note 19 – Related Party Transactions.

Through 2012, our general and administrative expenses, for any quarter therein, were comprised of:

Direct general and administrative expenses incurred by QRM on our behalf (“Direct G&A”) and charged to us;

Administrative service fees, as discussed in Note 19 – Related Party Transactions, payable by us to QRM during the term of the Services Agreement; and

We were not required to reimburse QRM for Allocated G&A in excess of administrative service fees during the initial term of the Services Agreement through 2012. Therefore, these allocated expenses were recorded as capital contributions from the Fund in our Consolidated Statement of Partner’s Capital. This allocation methodology, based on relative production volumes, has been reviewed and approved by QRE GP’s board of directors, including independent directors, as a reasonable method of sharing these expenses with the Fund and provides for a reasonably accurate depiction of what our general and administrative expenses would be on a stand-alone basis without affiliations with the Fund or QRM.

After December 31, 2012, the Partnership was required to reimburse QRM for its share of allocable general and administrative expenses based on the estimated use of such services. The Partnership reimburses QRM for general and administrative expenses allocated to us based on the estimated use of such services between us and the Fund. The fee includes Direct G&A plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If our sponsor raises additional funds in the future, the quarterly administrative services costs will be further divided to include the sponsor’s additional funds as well. QRM has discretion to determine in good faith the proper allocation of the charges pursuant to the Services

F–14

Agreement. Management believes this allocation methodology is a reasonable method of allocating general and administrative expenses between us and the Fund and provides for a reasonably accurate depiction of what our general and administrative expenses would be on a stand-alone basis without affiliations with the Fund or QRM.

Management Incentive Fee

Under our partnership agreement, as amended, for each quarter for which we pay distributions that are equal or greater than 115% of our minimum quarterly distribution (which we refer to as our “Target Distribution”), QRE GP will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of a management incentive fee base. With the expiration of the subordination period on December 22, 2012 and having received three full quarters of management incentive fees, QRE GP became eligible to convert up to 80% of its fourth quarter 2012 management incentive fee for 6,133,558 Class B units. On February 22, 2013, QRE GP elected to convert 80% of their fourth quarter management incentive fee and, on March 4, 2013, received 6,133,558 Class B units. The calculation of the management incentive fee and conversion and the current year expense is discussed further in Note 19 – Related Party Transactions.

Income Taxes

We are treated as a partnership for federal income tax purposes except for the income and losses generated from our controlling interest in the ETSWDC. Our federal taxable income and losses are primarily reported on the income tax returns of the partners. We are also subject to the Texas Margin tax which is derived from our taxable income apportioned to Texas. Refer to Note 18 – Income Taxes for further details of our tax accounts.

We use the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to the taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities from a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

We performed evaluations as of December 31, 2013 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.

Net Income (Loss) per Limited Partner Unit

Net income (loss) per limited partner unit is determined by dividing net income available to the limited partners, after deducting distributions to preferred unitholders, the general partner’s 0.1% interest in net income, and net income attributable to non-controlling interest, by the weighted average number of limited partner units outstanding. Income from the October 2011 Transferred Properties and the December 2012 Transferred Properties is excluded from the calculation of net income (loss) per limited partner as the income relates to the Predecessor operations. The Preferred Units and the management incentive fee, to the extent eligible for conversion into Class B units, are contingently convertible and will be included in the denominator for diluted income per unit unless they are anti-dilutive. See Note 13 – Net Income (Loss) Per Limited Partner Unit.

Business Segment Reporting

We operate in one reportable segment engaged in the development, exploitation and production of oil and natural gas properties. All of our operations are located in the United States.

Equity-Based Compensation

We have granted equity-classified restricted unit awards which we account for at fair value. Restricted unit awards, net of estimated forfeitures, are expensed over the requisite service period. As each award vests, an adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the vested awards. For equity-based awards that contain service conditions, compensation cost is recorded using the straight-line method. For equity-based performance awards that contain a market condition,

F–15

we estimate the grant date fair value based on the fair value derived from the Monte Carlo model and record the expense using the straight-line method over the performance period.

During 2013, 2012 and 2011 we have granted awards to employees and directors of QRM who performed services for us. We record these compensation costs as direct general and administrative expenses. See Note 15 – Equity Based Compensation.

Recent Accounting Pronouncements

Effective with the acquisition of ETSWDC in August 2013, we adopted ASU 2013-02, Comprehensive Income: Reporting Amounts Reclassified Out of Accumulated Other Comprehensive Income (AOCI). The ASU requires aggregated disclosures of amounts reclassified out of AOCI as well as a presentation of changes in AOCI balances by component. The changes in AOCI by component, including amounts reclassified out of AOCI in their entirety are presented in the consolidated statement of comprehensive income. This update did not impact our balance sheet, results of operations or cash flows.

In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The ASU clarifies that ASU 2011-11, discussed above, ordinary trade receivables and receivables are not in the scope of ASU 2011-11. This ASU issuance does not change our evaluation of ASU 2011-11 on our disclosures as noted below.

In December 2011, the FASB issued ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). The objective of this update is to provide enhanced disclosures that will enable the users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The amendment requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to the master netting arrangement. This scope does not include financial and derivative instruments that either offset in accordance with U.S. GAAP or are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with U.S. GAAP. This amendment became effective for annual reporting periods beginning on or after January 1, 2013, and the interim periods within those annual periods. This update, which expanded disclosures, was adopted by us in January 2013 and did not have a material impact on our financial position, results of operations or cash flows.

NOTE 3 — OIL AND GAS ASSETS

Costs Excluded From Amortization

The following is a summary of our oil and gas properties not subject to amortization:


	December 31,		December 31,
		2013		2012
Acquisition of unevaluated properties:
Incurred in 2013	$	-	$	-
Incurred in 2012		4,320		11,500
Incurred in 2011 and prior		-		-
Total oil and gas properties not subject to amortization	$	4,320	$	11,500

The 2012 total costs excluded from the amortization base were obtained in the Prize Acquisition and the 2012 East Texas Acquisition. We believe that our evaluation activities related to all of our properties not subject to amortization will be completed within five years.

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NOTE 4 — ACQUISITIONS

Third Party Acquisitions

2013 East Texas Oil Field Acquisition

On August 6, 2013, we closed the acquisition of primarily oil properties located in East Texas (the “2013 East Texas Acquisition”) from a private seller for $107.8 million cash, subject to customary purchase price adjustments, using funds drawn on our revolving credit facility. The acquired properties (the “2013 East Texas Properties”) had estimated proved reserves of 5.9 MMBoe as of the date of the acquisition utilizing SEC case pricing. The acquisition had an effective date of June 1, 2013. The costs associated with the 2013 East Texas Acquisition of $0.4 million are recorded in “Acquisition and transaction costs” on our consolidated statements of operations for the year ended December 31, 2013. In connection with the 2013 East Texas Acquisition, we assumed an estimated environmental liability of $0.5 million. Refer to Note 11 – Commitments and Contingencies for further details. Since the closing date, revenues of $60 million and production expenses of $15.2 million related to the operation of the 2013 East Texas Properties are included in our consolidated statements of operations for year ended December 31, 2013.

In connection with the 2013 East Texas Acquisition, we also acquired a 32% interest in ETSWDC giving us control of ETSWDC as we previously owned 24%. During the fourth quarter 2013 we acquired an additional 3% from another seller giving us a 59% ownership interest as of December 31, 2013. As of the closing date of the 2013 East Texas Acquisition, we have a controlling interest in the ETSWDC and have consolidated ETSWDC into our consolidated financial statements. In addition, our previous ownership in ETSWDC was remeasured to fair value on the acquisition date resulting in a gain of $1.3 million recognized in “Other income (expense)” in our consolidated statements of operations.

The 2013 East Texas Acquisition qualified as a business combination and was accounted for under the purchase method of accounting. The fair value measurements of the oil and gas properties, the investment in ETSWDC, and asset retirement obligations were measured using valuation techniques and unobservable inputs that convert future cash flows to a single discounted amount.

The following table summarizes the estimated preliminary fair values of the assets acquired and liabilities assumed as of the closing date:


Oil and gas properties	$	105,141
Investment in ETSWDC		9,576
Asset retirement obligation		(6,069)
Other current liabilities		(884)
Net assets acquired	$	107,764

The following table summarizes the estimated preliminary fair values of the ETSWDC assets and liabilities along with the fair value of the noncontrolling interest to derive our investment in ETSWDC acquired in the 2013 East Texas Acquisition.


Assets acquired and liabilities assumed:
Current assets (1)	$	7,858
Property, plant and equipment, net		13,103
Other long term assets		16,215
Total assets		37,176
Liabilities:
Current liabilities		(1,761)
Asset retirement obligation		(4,607)
Pension and postretirement benefits		(12,039)
Total liabilities		(18,407)
Fair value of saltwater disposal company		18,769
Less: remeasurement of previously held interest		(3,237)
Less: fair value of noncontrolling interest		(5,956)
Fair value of ETSWDC acquired by QR Energy, LP	$	9,576

⁽¹⁾

Includes $3.5 million of cash and cash equivalents.

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The above estimated preliminary fair values of assets acquired and liabilities assumed are provisional and are based on the information that was available as of the acquisition date to estimate the fair value of assets acquired and liabilities assumed. We believe that the information provides a reasonable basis for estimating the fair values of assets acquired and liabilities assumed. We expect to finalize the valuation and complete the purchase price allocation as soon as practicable but no later than one year from the acquisition date.

Other 2013 Acquisitions

During the fourth quarter of 2013, we also closed various small acquisitions of oil and gas properties with an aggregate purchase price of $22.6 million in cash, subject to customary purchase price adjustments, using funds drawn from our revolving credit facility.

2012 East Texas Oil Field Acquisition

On December 4, 2012 we closed the East Texas Oil Field Acquisition (the “2012 East Texas Acquisition"). We acquired the East Texas Oil Field Properties (the “2012 East Texas Properties”) for $214.3 million in cash after customary purchase price adjustments. 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. The costs associated with the 2012 East Texas Acquisition of $0.3 million are recorded in “Acquisition and transaction costs” in the consolidated statement of operations for the year ended December 31, 2012. The 2012 East Texas Acquisition qualified as a business combination and was accounted for under the purchase method of accounting. The fair value measurements of the oil and gas properties and asset retirement obligations were measured using valuation techniques and unobservable inputs that convert future cash flows to a single discounted amount.

The following table summarizes the fair values of the assets acquired and liabilities assumed as of the acquisition closing date:


Oil and gas properties
Evaluated (1)	$	218,039
Unevaluated		5,400
Other Assets		1,900
Asset retirement obligation		(9,843)
Other current liabilities		(1,190)
Net assets acquired	$	214,306

⁽¹⁾

Includes receivable from seller for customary purchase price adjustments recorded in prepaid and other current assets as of December 31, 2012, which was received during 2013.

Prize Acquisition

On April 20, 2012 we closed the Prize Acquisition. We acquired predominantly low decline, long life oil properties, almost all of which are located in the Ark-La-Tex area, for $225.1 million in cash after customary purchase price adjustments. The acquired properties had estimated proved reserves as of December 31, 2011 utilizing SEC case pricing of 13.3 MMBoe. The acquisition had an effective date of January 1, 2012. The costs associated with the Prize Acquisition of $1.1 million are recorded in “Acquisition and transaction costs” in the consolidated statement of operations for the year ended December 31, 2012. In conjunction with the Prize Acquisition, we assumed an estimated environmental liability of $1.9 million. Refer to Note 11 – Commitments and Contingencies for further details. Since the closing date, revenues of $24.6 million and operating expenses of $8.3 million related to the operation of the Prize properties are included in the consolidated statements of operations for the year ended December 31, 2012. The Prize Acquisition qualified as a business combination and was accounted for under the purchase method of accounting. The fair value measurements of the oil and gas properties and asset retirement obligations were measured using valuation techniques and unobservable inputs that convert future cash flows to a single discounted amount.

F–18

The following table summarizes the fair values of the assets acquired and liabilities assumed as of the acquisition closing date:


Oil and gas properties
Evaluated	$	226,670
Unevaluated		6,100
Asset retirement obligation		(4,738)
Environmental liability		(1,891)
Other current liabilities		(993)
Net assets acquired	$	225,148

Pro forma Financial Data

The following unaudited pro forma income statement information for years ended December 31, 2013 and 2012 assumes the 2013 East Texas Acquisition had occurred on January 1, 2012, and the Prize Acquisition and the 2012 East Texas Acquisition had occurred on January 1, 2011. The unaudited pro forma results reflect certain adjustments related to the acquisitions, such as increased depreciation and amortization expense on the fair value of the assets acquired. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisition been completed at the beginning of the periods presented, nor are they indicative of future results of operations.


		Year Ended
		(Unaudited)
		December 31, 2013		December 31, 2012
		Pro Forma		Pro Forma
Total revenues	$	485,284	$	476,345
Operating income	$	115,104	$	104,327
Net income attributable to QR Energy, LP	$	66,068	$	107,238
Net income per unit:
Common unitholders' (basic)	$	0.34	$	0.75
Common unitholders' (diluted)	$	0.34	$	0.73
Subordinated units (basic and diluted)	$	-	$	0.78

Affiliated Acquisitions

On December 28, 2012, we completed our acquisition of the December 2012 Transferred Properties from the Fund in exchange of $28.6 million in cash, after customary purchase price adjustments, and the assumption of $115 million in debt. The net assets were recorded by the Partnership using historical book value of the Fund as the acquisition is a transaction between entities under common control. Our historical financial statements were revised to include the results attributable to the December 2012 Transferred Properties as if we owned the properties for all periods presented in our consolidated financial statements. See Note 1 – Organization and Operations for further disclosures regarding this transaction. See Note 2 – Summary of Significant Accounting Policies for further discussion regarding the accounting policies for transactions between entities under common control.


Oil and gas properties
Evaluated	$	141,315
Accumulated depreciation, depletion, and amortization		(45,416)
Other assets (1)		10,732
Derivative instruments, net		(2,948)
Long-term debt		(115,000)
Asset retirement obligation		(34,261)
Book value of net assets		(45,578)
Purchase price adjustment		5,270
Net assets contributed by the Predecessor (2)	$	(40,308)

⁽¹⁾

Represents a reclamation deposit in escrow as security for abandonment and redemption obligations.

⁽²⁾

The net assets contributed to us include the historical book value of the Predecessor as prescribed by our accounting policy for transactions between entities under common control in Note 2 – Summary of Significant Accounting Policies and a $5.3 million purchase price adjustment related to novated derivatives unwound by the Partnership.

F–19

Effective October 1, 2011, we completed our acquisition of the October 2011 Transferred Properties from the Fund in exchange for 16,666,667 Class C Convertible Preferred Units and the assumption of $227 million in debt. The net assets were recorded by the Partnership using historical book value of the Fund as the acquisition is a transaction between entities under common control. See Note 1 – Organization and Operations for further disclosures regarding this transaction.


Oil and gas properties, net	$	441,207
Gas processing equipment, net		251
Derivative instrument asset, net		64,671
Deferred tax asset		205
Long-term debt		(227,000)
Asset retirement obligation		(26,294)
Natural gas imbalance		(3,709)
Book value of net assets		249,331
Purchase price adjustments		2,715
Net assets contributed by the Predecessor (1)	$	252,046

⁽¹⁾

The net assets contributed to us include the historical book value of the Predecessor as prescribed by our accounting policy for transactions between entities under common control in Note 2 – Summary of Significant Accounting Policies and a $2.7 million purchase price adjustment for natural gas imbalances in accordance with the purchase and sale agreement.

NOTE 5 — INVESTMENTS

Our available for sale securities consist of investments not classified as trading securities or as held-to-maturity. Our investments are classified as “Other assets” on our consolidated balance sheet.

As of December 31, 2012, we had no available for sale investments outstanding. As of December 31, 2013, we had the following available for sale investments outstanding:


			Gross		Gross
	Cost Basis		Unrealized Gains		Unrealized Losses		Fair Value

Available-for-sale securities:
Equities	$	3,647	$	361	$	41	$	3,967
Mutual funds		11,339		320		20		11,639
Exchange traded funds		2,924		217		1		3,140
Total for available-for-sale securities	$	17,910	$	898	$	62	$	18,746

During the year ended December 31, 2013 we received $8.6 million in proceeds from the sale of available-for-sale securities with a realized loss of less than $0.1 million.

We evaluate securities for other than temporary impairment on a quarterly basis and more frequently when economic or market concerns warrant such an evaluation. The unrealized losses above have been outstanding for less than six months. We have evaluated the unrealized losses above and have determined that these losses do not represent an other than temporary impairment.

NOTE 6 — FAIR VALUE MEASUREMENTS

Our financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Our financial and non-financial assets and liabilities that are being measured on a recurring basis are measured and reported at fair value.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:

F–20

Level 1 - Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 - Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.

Level 3 - Defined as unobservable inputs for use when little or no market data exists, therefore requiring amenity to develop its own assumptions for the asset or liability.

Commodity Derivative Instruments – The fair value of the commodity derivative instruments are estimated using a combined income and market valuation methodology based upon forward commodity prices and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

Interest Rate Derivative Instruments – The fair value of the interest rate derivative instruments are estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

Available for Sale Securities – The fair value of the available for sale securities are estimated using actual trade data, broker/dealer quotes, and other similar data, which are obtained from quoted market prices, independent pricing vendors, or other sources. We validate the data provided by independent pricing services to make assessments and determinations as to the ultimate valuation of its investment portfolio by comparing such pricing against other third party pricing data.

We utilize the most observable inputs available for the valuation technique utilized. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement.

The following table sets forth, by level within the hierarchy, the fair value of our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012. All fair values reflected below and on the consolidated balance sheet have been adjusted for nonperformance.


As of December 31, 2013		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	89,616	$	-	$	89,616	$	-
Available for sale securities:
Equities		3,967		3,967		-		-
Mutual funds		11,639		11,639		-		-
Exchange traded funds		3,140		3,140		-		-
	$	108,362	$	18,746	$	89,616	$	-

Liabilities from commodity derivative instruments	$	7,093	$	-	$	7,093	$	-
Liabilities from interest rate derivative instruments		10,391		-		10,391		-
	$	17,484	$	-	$	17,484	$	-

As of December 31, 2012	Total		Level 1		Level 2			Level 3
Assets from commodity derivative instruments	$	122,143	$	-	$	122,143	$	-
	$	122,143	$	-	$	122,143	$	-

Liabilities from commodity derivative instruments	$	13,484	$	-	$	13,484	$	-
Liabilities from interest rate derivative instruments		12,236		-		12,236		-
	$	25,720	$	-	$	25,720	$	-

Fair Value of Other Financial Instruments

Fair value guidance requires certain fair value disclosures, such as those on our long-term debt, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

Revolving Credit Facility – The fair value of our credit facility debt depends primarily on the current active market LIBOR. The carrying value of our credit facility debt as of December 31, 2013 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.

F–21

Derivative Premiums – The fair value of the deferred premiums on our commodity derivatives is based on the current active market LIBOR. The carrying value of the premiums as of December 31, 2013 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy. Refer to Note 7 – Derivative Activities for further information on the derivative premiums.

Senior Notes – The fair value of the Senior Notes is measured based on inputs from quoted, unadjusted prices from over-the-counter markets for debt instruments. If the Senior Notes had been measured at fair value, we would classify them as Level 1 under the fair value hierarchy. The fair value of the Senior Notes as of December 31, 2013 was $312.2 million.

There have been no transfers between levels within the fair value measurement hierarchy during the year ended December 31, 2013.

NOTE 7 — DERIVATIVE ACTIVITIES

We have elected not to designate any of our derivatives as hedging instruments. As a result, these derivative instruments are marked to market at the end of each reporting period, and changes in the fair value of the derivatives are recorded as gains or losses in the consolidated statements of operations.

Although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have presented all asset and liability positions without netting. 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 do not post collateral under any of these contracts as they are secured under our credit facility. All of our derivative contracts reflected in the consolidated balance sheet have been adjusted for nonperformance.

Commodity Derivatives

Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. As such, future earnings are subject to fluctuations due to changes in the market price of oil and natural gas. We use derivatives to reduce our exposure to changes in the prices of oil and natural gas. Our policies do not permit the use of derivatives for speculative purposes.

During the year ended December 31, 2012, we terminated certain oil derivative contracts that were novated to us in connection with the December 2012 Transferred Properties which were scheduled to expire at various times in 2013 and recorded $5.3 million as an adjustment to the purchase price.

The deferred premiums associated with certain of our oil and natural gas derivative instruments are $5.0 million and $4.9 million and are classified as other non-current liabilities on the consolidated balance sheets as of December 31, 2013 and 2012. These deferred premiums will be paid to the counterparty with each monthly settlement (January 2015 – December 2017) and recognized as an adjustment of Gain (loss) on commodity derivative contracts, net.

F–22

We hold commodity derivative contracts to manage our exposure to changes in the price of oil and natural gas related to our oil and natural gas production. As of December 31, 2013, the notional volumes of our commodity derivative contracts were:


Commodity	Index	2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		6,715		7,356		6,293		5,547
Average price ($/Bbls)		$	95.30	$	93.74	$	90.03	$	86.23
Hedged Volume (Bbls/d)	LLS		3,000		-		-		-
Average price ($/Bbls)		$	99.62		-		-		-
Basis
Hedged Volume (Bbls/d)	WTS/WTI		2,400		-		-		-
Average price ($/Bbls)		$	(2.10)		-		-		-
Collars
Hedged Volume (Bbls/d)	WTI		425		1,025		1,500		-
Average floor price ($/Bbls)		$	90.00	$	90.00	$	80.00		-
Average ceiling price ($/Bbls)		$	106.50	$	110.00	$	102.00		-

Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		26,622		7,191		11,350		10,445
Average price ($/MMBtu)		$	6.18	$	5.34	$	4.27	$	4.47
Basis Swaps (1)
Hedged Volume (MMBtu/d)	Henry Hub		17,066		14,400		-		-
Average price ($/MMBtu)		$	(0.19)	$	(0.19)		-		-
Collars
Hedged Volume (MMBtu/d)	Henry Hub		4,966		18,000		630		595
Average floor price ($/MMBtu)		$	5.74	$	5.00	$	4.00	$	4.00
Average ceiling price ($/MMBtu)		$	7.51	$	7.48	$	5.55	$	6.15
Puts
Hedged Volume (MMBtu/d)	Henry Hub		-		420		11,350		10,445
Average price ($/MMBtu)			-	$	4.00	$	4.00	$	4.00

⁽¹⁾

Our natural gas basis swaps are used to hedge the differential between Henry Hub and various points.

Interest Rate Derivatives

During 2013, we entered into $410 million of new interest rate swaps with termination dates through 2016. The new contracts were entered into with various financial institutions.

On July 31, 2012, we terminated certain interest rate derivative contracts which were scheduled to expire at various times through the fourth quarter 2015 and recorded a $15 million realized loss for the early termination.

Credit Risk

By using derivative instruments to hedge exposures to changes in commodity prices and interest rates, when applicable, we are exposed to credit risk. Credit risk is the failure of a counterparty to perform under the terms of the derivative contract. When the fair value of a derivative is in an asset position, the counterparty owes the Partnership, which creates credit risk. We do not receive collateral from our counterparties. The maximum amount of loss to credit risk, based on the gross fair value of our derivative contracts, is $1.1 million as of December 31, 2013.

F–23

Financial Statement Presentation of Derivatives

The fair value of our derivatives as recorded on our balance sheet was as follows as of the dates indicated:


	December 31, 2013				December 31, 2012
	Asset		Liability		Asset		Liability
	Derivatives		Derivatives		Derivatives		Derivatives

Commodity contracts	$	89,616	$	7,093	$	122,143	$	13,484
Interest rate contracts		-		10,391		-		12,236
	$	89,616	$	17,484	$	122,143	$	25,720

Commodity
Current	$	27,485	$	5,651	$	45,522	$	4,130
Noncurrent		62,131		1,442		76,621		9,354
	$	89,616	$	7,093	$	122,143	$	13,484
Interest
Current	$	-	$	5,582	$	-	$	4,597
Noncurrent		-		4,809		-		7,639
	$	-	$	10,391	$	-	$	12,236

Total Derivatives
Current	$	27,485	$	11,233	$	45,522	$	8,727
Noncurrent		62,131		6,251		76,621		16,993
	$	89,616	$	17,484	$	122,143	$	25,720

The following table presents our derivatives on a net basis as of the indicated periods:


	December 31, 2013				December 31, 2012
		Asset		Liability		Asset		Liability
		Derivatives		Derivatives		Derivatives		Derivatives
Gross derivatives	$	89,616	$	17,484	$	122,143	$	25,720
Netting		(2,960)		(2,960)		(11,594)		(11,594)
Net derivatives	$	86,656	$	14,524	$	110,549	$	14,126

The following table presents the impact of derivatives and their location within the consolidated statements of operations for the indicated periods:


	Year Ended
	December 31,		December 31,		December 31,
	2013		2012		2011
Total gains (losses):
Commodity contracts (1)	$	(1,217)	$	53,071	$	47,860
Interest rate contracts (2)		(2,913)		(10,221)		(29,426)
Total	$	(4,130)	$	42,850	$	18,434

⁽¹⁾

Gain (loss) on commodity derivative contracts is located in other income (expense) in the consolidated statements of operations.

Gain (loss) on interest rate derivative contracts is recorded as part of interest expense and is located in other income (expense) in the consolidated statements of operations.

NOTE 8 — ASSET RETIREMENT OBLIGATIONS

The total undiscounted amount of future cash flows to settle our asset retirement obligations is estimated to be $352.5 million and $275.0 million at December 31, 2013 and 2012. Payments to settle asset retirement obligations occur over the lives of the gas properties and other plant, property and equipment, estimated to be from less than one year to 45 years.

F–24

Changes in the asset retirement obligations are presented in the following table:



	Year Ended
	December 31, 2013		December 31, 2012
Beginning of period	$	126,991	$	92,561
Assumed in acquisitions		13,409		14,581
Revisions to previous estimates (1)		12,911		17,278
Liabilities incurred		360		1,185
Liabilities settled		(5,806)		(4,262)
Accretion expense		7,456		5,648
End of period	$	155,321	$	126,991
Less: Current portion of asset retirement obligations		4,310		1,426
Asset retirement obligations - non current	$	151,011	$	125,565

⁽¹⁾

In 2013 and 2012, we recorded an upward revision to previous estimates for our asset retirement obligations primarily due to changes in the estimated abandonment dates.

NOTE 9 — PENSIONS AND POSTRETIREMENT BENEFITS

The ETSWDC sponsors a noncontributory defined benefit pension plan and a contributory other post-retirement benefit plan (collectively, the “Plans”) covering substantially all ETSWDC employees who were employed prior to March 31, 2008. Subsequent to March 31, 2008, the Plans were closed to new employees. The tables below set forth the benefit obligation, fair value of plan assets, and the funded status of the Plans; amounts recognized in the Partnership’s financial statements; and the principal weighted average assumptions used.

Obligation and Funded Status

The Plans have accumulated benefit obligations in excess of plan assets as shown in the table below:


		December 31, 2013
		Pension Benefits		Postretirement Benefits
Projected benefit obligation	$	23,592	$	3,922
Accumulated benefit obligation		22,724		3,922
Fair value of plan assets		20,466		1,438

The change in the combined projected benefit obligation of the Plans and the change in the assets at fair value are as follows:


	Year Ended December 31, 2013
		Pension Benefits		Postretirement Benefits
Change in Benefit Obligation
Benefit obligation at beginning of year	$	-	$	-
2013 East Texas Oil Field Acquisition		24,697		8,326
Service cost		135		29
Interest cost		429		145
Plan participant contributions		-		25
Actuarial (gain) loss		(1,136)		(4,364)
Benefits paid		(533)		(239)
Benefit obligation at end of year		23,592		3,922
Change in Plan Assets
Fair value of plan assets at beginning of year		-		-
2013 East Texas Oil Field Acquisition		19,518		1,466
Actual return on plan assets		1,127		91
Employer contributions		354		95
Plan participant contributions		-		25
Benefits paid		(533)		(239)
Fair value of plan assets at end of year		20,466		1,438
Under funded status at end of year	$	(3,126)	$	(2,484)

F–25

Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet consist of the following:


		Pension Benefits				Postretirement Benefits
		Year Ended				Year Ended
		December 31,				December 31,
		2013		2012		2013		2012
Current liabilities	$	-	$	-	$	-	$	-
Long-term liabilities		3,126		-		2,484		-
	$	3,126	$	-	$	2,484	$	-

Components of Net Periodic Benefit Cost and Other Comprehensive Income

Net periodic benefit costs recognized in the consolidated statements of operations consist of the following for the indicated periods:


		Pension Benefits				Postretirement Benefits
		Year Ended				Year Ended
		December 31,				December 31,
		2013		2012		2013		2012
Service cost	$	135	$	-	$	29	$	-
Interest cost		429		-		145		-
Expected return on plan assets		(529)		-		(35)		-
Net periodic postretirement benefit costs	$	35	$	-	$	139		-

Amounts recognized in accumulated other comprehensive income consist of the following:


		Pension Benefits				Postretirement Benefits
		Year Ended				Year Ended
		December 31,				December 31,
		2013		2012		2013		2012
Prior service cost	$	-	$	-	$	-	$	-
Net actuarial gain:
Liability gain due to assumption change		735		-		(2,189)		-
Liability gain due to participant experience		401		-		(2,175)		-
Asset return gain		598		-		(56)		-
Net actuarial gain		1,734		-		(4,420)		-
Total	$	1,734	$	-	$	(4,420)	$	-

Estimated Future Benefit Payments

The following estimated benefit payments under the Plans, which reflect expected future service, as appropriate, are expected to be paid as follows:


		Pension Benefits		Other Benefits
2014	$	1,430	$	180
2015		1,530		240
2016		1,530		230
2017		1,590		240
2018		1,620		250
2019-2023		8,390		1,260

The ETSWDC expects to contribute approximately $1.1 million and $0.2 million to the pension and other postretirement plan, respectively, in 2014.

F–26

Assumptions

Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:


	Pension Benefits				Postretirement Benefits
	Year Ended				Year Ended
	December 31,				December 31,
	2013			2012	2013		2012
Discount rate	4.50		%	-	4.50	%	-
Rate of compensation increase	3.00		%	-	N/A		N/A
Health care cost trend rate:
Pre - 65 rate	N/A			N/A	7.00	%	-
Post - 65 rate	N/A			N/A	5.00	%	-
Expected long-term rates of return on plan assets	6.75	%		-	6.75	%	-

Assumptions used to determine net periodic benefit costs are as follows:


	Pension Benefits			Postretirement Benefits
	Year Ended			Year Ended
	December 31,			December 31,
	2013		2012	2013		2012
Discount rate	4.25	%	-	4.25	%	-
Expected long-term return on plan assets	6.75	%	-	5.75	%	-
Rate of compensation increase	3.50	%	-	N/A		-

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:


	Postretirement Benefits
		1-Percentage-		1-Percentage-
		Point Increase		Point Decrease
Effect on total service and interest cost	$	26	$	22
Effect on postretirement benefit obligation		417		353

The following table presents the fair values of our pension plan assets by level within the fair value hierarchy, as of December 31, 2013


	December 31, 2013
		Level 1		Level 2		Level 3		Total
Equity securities:
Pooled Funds (1)	$	-	$	9,239	$	-	$	9,239
Fixed income securities:
Pooled Funds (2)		-		11,227		-		11,227
Total investments, at fair value	$	-	$	20,466	$	-	$	20,466

⁽¹⁾

Investments consist primarily of pooled separate accounts which focus on long-term growth of capital through U.S. and international securities.

⁽²⁾

Investments consist primarily of pooled separate accounts which focus on long-term growth of capital and preservation of equity though U.S. and international securities.

The following table presents the fair values of our postretirement benefit plan assets by level within the fair value hierarchy, as of December 31, 2013.


	December 31, 2013
		Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	333	$	-	$	-	$	333
Equity securities:
Mutual Funds (1)		370		-		-		370
Fixed income securities:
Corporate bonds		735		-		-		735
Total investments, at fair value	$	1,438	$	-	$	-	$	1,438

⁽¹⁾

Investments consist primarily of mutual funds which focus on growth of capital and income maximization.

F–27

Plan Investment Policies and Strategies

The investment policies for the Plans reflect the funded status of the Plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the Plans’ investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation.

Historical performance and future expectations suggest that common stocks will provide higher total investment returns than fixed income securities over a long-term investment horizon. Short-term investments are utilized for pension payments, expenses, and other liquidity needs. As such, the Plan’s targeted asset allocation is comprised of approximately 50 percent equity securities and approximately 50 percent high-yield bonds and other fixed income securities but may be adjusted to better match the plan's liabilities over time as the funded ratio (as defined by the investment policy) changes.

The Plans’ assets are managed by a third-party investment manager. The investment manager is limited to pursuing the investment strategies regarding asset mix and purchases and sales of securities within the parameters defined in the investment policy guidelines and investment management agreement. Investment performance and risk is measured and monitored on an ongoing basis through annual investment meetings and periodic cash flow studies.

Expected long-term return on plan assets

The overall expected long-term return on plan assets assumption is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account the Plans’ asset allocations to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.

Fair Value Measurements

Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 2013.

Cash and cash equivalents – Cash and cash equivalents include cash on deposit which are valued using a market approach and are considered Level 1.

Mutual funds – Investments in mutual funds are valued using a market approach. The shares or units held are traded on the public exchanges and such prices are Level 1 inputs.

Pooled funds – Investments in pooled funds are valued using a market approach at the net asset value of units held, but investment opportunities in such funds are limited to institutional investors on the behalf of defined benefit plans. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2.

Corporate bonds – Investments in corporate bonds are valued using a market approach. Bonds are valued at the closing price reported on the active market on which the securities are traded and are considered Level 1.

F–28

NOTE 10 — LONG-TERM DEBT

Consolidated debt obligations consisted of the following as of the dates indicated:


	Year Ended
	December 31,
	2013		2012
Senior secured revolving credit facility	$	615,000	$	470,000
9.25% Senior Notes due 2020 (1)		296,593		296,076
	$	911,593	$	766,076

Letters of credit (2)	$	23,488	$	23,488

⁽¹⁾

The amount is net of unamortized discount of $3.4 and $3.9 million as of December 31, 2013 and 2012, respectively.

⁽²⁾

These letters of credit relate to a reclamation deposit requirement. Refer to Note 11 – Commitments and Contingencies for details.

Revolving Credit Facility

On December 22, 2010, in connection with the IPO, the Partnership entered into a Credit Agreement along with QRE GP, OLLC as borrower, and a syndicate of banks (the “Credit Agreement”).

As of December 31, 2013, we had a $950 million borrowing base, $615.0 million of borrowings outstanding and $23.5 million of letters of credit issued resulting in $311.5 million of borrowing availability. During 2013, our weighted-average interest rate paid on our variable debt obligation was 3.6%, excluding the impact of hedges. At December 31, 2013, our weighted average-interest on the variable debt obligation was 2.2%, excluding the potential impact of hedges.

Effective March 2, 2014, we entered into the sixth amendment to the Credit Agreement, which permits the GP Buyout Transaction. See Note 22 – Subsequent Events.

On October 15, 2013, our revolving credit facility borrowing base increased to $950 million as a result of our semi-annual borrowing base redetermination.

Effective August 6, 2013, we entered into the fifth amendment to the Credit Agreement, which provides for the exclusion of ETSWDC as a guarantor of our credit facility.

In December 2012, we entered into the fourth amendment to the Credit Agreement that was effective January 15, 2013. The amendment, among other things, increased the borrowing base from $730 million to $900 million and increased the letters of credit commitment from $20 million to $30 million.

In July 2012, our borrowing base was reduced by $75 million to $655 million from $730 million as result of the issuance of the Senior Notes on July 30, 2012. In connection with the reduction of the borrowing base, we wrote-off approximately $0.7 million of deferred loan costs associated with the Credit Agreement. On October 30, 2012, as part of our semi-annual borrowing base redetermination, our borrowing base returned to $730 million.

During 2012, we entered into the second and third amendments to the Credit Agreement that, among other things, (i) provided for additional derivative contracts to cover production of proved reserves to be acquired, (ii) increased our credit facility from $750 million to $1.5 billion, increasing our borrowing base from $630 million to $730 million effective April 2012 and (iii) extended the maturity date from December 22, 2015 to April 20, 2017.

As of December 31, 2013, the Credit Agreement provides for a five-year, $1.5 billion revolving credit facility maturing on April 20, 2017, with a borrowing base of approximately $950 million. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ pricing assumptions, and other various factors unique to each member bank. The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the

F–29

prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum.

The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and also requires us to provide audited financial statements within 90 days of year end and quarterly unaudited financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of December 31, 2013, we were in compliance with all of the Credit Agreement covenants.

9.25% Senior Notes

On July 30, 2012, we and our wholly-owned subsidiary QRE FC, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 9.25% Senior Notes, due 2020 (the “Senior Notes”). The Senior Notes were issued at 98.62% of par. We received approximately $291.2 million of cash proceeds, net of the discount and underwriting fees, with total net proceeds of approximately $290.2 million, after $1.0 million of offering costs. We used the net proceeds from the sale of the Senior Notes to repay borrowings outstanding under our credit facility. In 2012, we filed and completed a registration statement with the SEC to allow holders of the Senior Notes to exchange for registered Senior Notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012 and the exchange offer was completed on November 7, 2012. We will have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture governing the Senior Notes. Our and QRE FC’s obligations under the Senior Notes are guaranteed by OLLC. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor’s, other debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Note 20 – Subsidiary Guarantors for further details of our guarantors.

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will cease to be subject to such covenants. The Indenture also includes customary events of default. As of December 31, 2012, the Partnership is in compliance with all financial and other covenants of the Senior Notes.

On September 7, 2012, we 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 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.

Bridge Loan Commitment

NOTE 11 — COMMITMENTS AND CONTINGENCIES

Services Agreement

We have entered into the Services Agreement with QRM as described in Note 18 – Related Party Transactions. Beginning 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. Through December 31, 2012, QRM was entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined by the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee.

Property Reclamation Deposit

In connection with the December 2012 Transaction, we acquired a property reclamation deposit for future abandonment and remediation obligations. In connection with a 2006 acquisition between ExxonMobil Corporation and the Fund, $10.7 million was required to be deposited into an escrow account as security for abandonment and remediation obligations. As of December 31, 2013 and 2012, $10.7 million was recorded in other assets related to the deposit. We are required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to the Partnership until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, we have the right to request a refund of a portion or all of the property reclamation deposit. Granting of the request is at the seller’s sole discretion. In addition to the cash deposit, we were required to provide a $3.0 million letter of credit; the agreement also requires an additional $3.0 million letter of credit to be issued in favor of the seller each year through 2012. Letters of credit totaling $23.5 million are issued as of December 31, 2013.

Environmental Contingencies

As of December 31, 2013 and 2012, we have approximately $2.3 million and $1.9 million in environmental liabilities, respectively, related to the 2013 East Texas Acquisition and the Prize Acquisition. This is management’s best estimate of the costs of remediation and restoration with respect to these environmental matters, although the ultimate cost could differ materially. The environmental liability is recorded in Other liabilities on the consolidated balance sheet. Inherent uncertainties exist in these estimates primarily due to unknown conditions, changing governmental regulation and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration.

NPI Obligation

As a part of the December 2012 Acquisition, we assumed a net profit interest obligation. Under the arrangement with the outside interest, we carry the working interest until historical expenditures are recovered. Once the expenditures are recovered, we will not carry the interest but will retain the future development costs and

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abandonment obligation which is currently reflected in our asset retirement obligations as of December 31, 2013. The cost of this future obligation is funded through current proceeds attributable to the owner’s interest.

Lease Guarantees

The Fund has entered into various lease contracts that can routinely extend beyond five years which list the Partnership as a guarantor. In December 2012, we were named guarantor for QRM’s office lease in Houston, Texas with an approximate value of $26.8 million that terminates in 2022. Beginning in 2013, we were allocated a portion of this obligation as part of the general and administrative expense allocation process.

Legal Proceedings

In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Operating Lease Commitments

QRM is party to an office lease worth approximately $26.8 million that expires in 2022. Beginning in 2013, we were allocated a portion of this expense as part of the general and administrative expense allocation process discussed in Note 19 – Related Party Transactions.

NOTE 12 — PARTNERS’ CAPITAL

Units Outstanding

The table below details the outstanding units as of December 31, 2013, 2012 and 2011. As of December 31, 2013, the Fund owned all preferred units.


	Class C	General	Class B	Public	Affiliated
	Preferred Units	Partner	Units	Common	Common	Subordinated
Balance - December 31, 2010	-	35,729	-	15,000,000	11,297,737	7,145,866
Underwriters' exercise of over-allotment	-	-	-	2,250,000	-	-
Vested units awarded under our Long Term Incentive
Performance Plan	-	-	-	52,798	-	-
Reduction in units to cover individuals'
tax withholdings	-	-	-	(10,519)	-	-
Preferred Units issued to Predecessor
in exchange for Transferred October 2011 Properties	16,666,667	-	-	-	-	-
Balance - December 31, 2011	16,666,667	35,729	-	17,292,279	11,297,737	7,145,866
Vested units awarded under our Long Term Incentive
Performance Plan	-	-	-	96,890	-	-
Reduction in units to cover individuals'
tax withholdings	-	-	-	(14,891)	-	-
Issuance of units to the general partner	-	15,307	-	-	-	-
Affiliated unit sale to the public	-	-	-	11,297,737	(11,297,737)	-
Conversion of Subordinated Units	-	-	-	-	7,145,866	(7,145,866)
Unit offerings	-	-	-	22,627,263	-	-
Balance - December 31, 2012	16,666,667	51,036	-	51,299,278	7,145,866	-
Vested units awarded under our Long Term Incentive
Performance Plan	-	-	-	218,460	-	-
Reduction in units to cover individuals'
tax withholdings	-	-	-	(34,475)	-	-
Management incentive fee conversion			6,133,558
Balance - December 31, 2013	16,666,667	51,036	6,133,558	51,483,263	7,145,866	-

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On March 2, 2014 we completed a transaction related to our general partner interest pursuant to a Contribution Agreement. See Note 22 – Subsequent Events for more information.

On February 22, 2013, our general partner elected to convert the full 80% of the fourth quarter 2012 management incentive fee and, on March 4, 2013, received 6,133,558 Class B units which were issued and outstanding upon conversion. In exchange for the issuance of Class B units, management incentive fees payable in the future will, if earned, be reduced to the extent of this and any future conversions. As a result, in the first quarter 2013 our general partner received a reduced fourth quarter management incentive fee of $0.7 million and a distribution of $3.0 million on the Class B units related to the fourth quarter 2012.

On December 22, 2012, in connection with the expiration of the subordination period, the subordinated units held by the Fund were converted into affiliated common units and continued to be held by the Fund. The converted units will participate pro rata with the other common units in distributions of available cash.

On December 12, 2012, we issued 12,000,000 common units representing limited partnership interests in us to the public pursuant to a registration statement filed with the SEC (the “December 2012 Equity Offering”). In connection 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 they 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 underwriter’s discount of $9.0 million, were approximately $214.9 million.

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 to the public pursuant to a registration statement filed on Form S-1 with the SEC (the “April 2012 Equity Offering”). In connection with the April 2012 Equity Offering, the Partnership granted the underwriters an 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. 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.

On April 25, 2012, QRE GP purchased 6,018 general partner units in order to maintain its 0.1% ownership percentage in us. The units were purchased at a price of $19.18 per unit for $0.1 million.

On October 3, 2011, we issued 16,666,667 of Preferred Units to the Fund in connection with the October 2011 Transaction. See Class C Preferred Units below for further details.

On January 3, 2011, the underwriters exercised their over-allotment option associated with our IPO in December 2010 in full for 2,250,000 common units issued by the Partnership at $20.00 per unit.

Common Units

The common units have limited voting rights as set forth in our partnership agreement.

Pursuant to our partnership agreement, if at any time QRE GP and its affiliates own more than 80% of the outstanding common units, QRE GP has the right, but not the obligation, to purchase all of the remaining common

F–33

units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. QRE GP may assign this call right to any of its affiliates or to us.

Class B Units

Upon the expiration of the subordinated period on December 22, 2012, and subject to the limitations described below, our general partner has the continuing right, at any time when it has received all or any portion of the management incentive fee for three full consecutive quarters and shall be entitled to receive all or a portion of the management incentive fee for a fourth consecutive quarter, to convert into Class B units up to 80%, such percentage actually converted being referred to as the Applicable Conversion Percentage, of the management incentive fee for the fourth quarter in lieu of receiving a cash payment for such portion of the management incentive fee. Any conversion election made during a quarter must be made before payment of the management incentive fee in respect of the previous quarter and will be effective as of the first day of such quarter, and the Class B units issued upon such conversion will be entitled to distributions as if they were outstanding on the first day of such quarter.

The Class B units are immediately convertible into common units at the election of our general partner. Class B units have all the rights of common units except for the right to vote on matters requiring specific approval by common unitholders, and are allocated income in an amount that is equal to their distributions.

Class C Preferred Units

On October 3, 2011 (the “Issue Date”), we amended our First Amended and Restated Agreement of Limited Partnership to designate and create the Preferred Units and set forth rights, preferences and privileges of such units including distribution rights held by the Preferred Units and us. For the period beginning on the Issue Date and ending on December 31, 2014, we will distribute $0.21 per unit on a quarterly basis. Beginning on January 1, 2015, distributions on Preferred Units will be the greater of $0.475 per unit or the distribution payable on Common Units with respect to such quarter. The Preferred Units are only redeemable for cash in a complete liquidation. The Preferred Units are convertible into common units under specific circumstances at the option of either the holder or the Partnership into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment. The Preferred Units have the same voting rights as common units. As of December 31, 2013 we have accrued a fourth quarter distributions payable of $3.5 million to Preferred Unitholders which were paid in February 2014.

Holders could have converted the Preferred Units to common units on a one-to-one basis prior to October 3, 2013, after 30 consecutive trading days during which the volume-weighted average price for our common units equals or exceeds $27.30 per common unit. In addition, holders may convert the Preferred Units to common units on a one-to-one basis anytime on or after October 3, 2013. As of December 31, 2013 no such conversion had occurred.

If the holders have not converted the Preferred Units to common units by October 3, 2014, we may force conversion on a one-to-one basis, provided that conversion is in the 30 calendar days following 30 consecutive trading days during which the volume-weighted average price for common units equals or exceeds (1) $30.03, provided that (a) an effective shelf registration statement covering resales for the converted units is in place or (2) $27.30, provided that (a) above is satisfied and (b) there exists an arrangement for one or more investment banks to underwrite the converted unit sale following conversion (with proceeds equal to not less than $27.30 less (i) a standard underwriting discount and (ii) a customary discount not to exceed 5% of $27.30).

We may force conversion on a one-to-one basis after October 3, 2016, provided the conversion is in the 30 calendar days following 30 consecutive trading days during which the volume-weighted average price for common units equals or exceeds $27.30 and an effective shelf registration statement covering resales for the converted units is in place.

Registration Rights Agreement

In connection with the acquisition of the October 2011 Transferred Properties, on October 3, 2011, we entered into a Registration Rights Agreement with the Fund (the “Registration Rights Agreement”), which granted certain registration rights to the Fund, including rights to (a) cause the Partnership to file with the SEC up to five shelf registration statements under the Securities Act for the resales of the common units to be issued upon conversion of

F–34

the Preferred Units, and in certain circumstances, the resales of the Preferred Units, and (b) participate in future underwritten public offerings of the our common units.

These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective. As of March 2, 2014, the Fund has not requested a shelf registration be filed for the Preferred Units.

Subordinated Units

The principal difference between our common and subordinated units was that, in any quarter during the subordination period, the subordinated units were entitled to receive the minimum quarterly distribution of $0.4125 per unit ($1.65 per unit on an annualized basis) only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.

During Subordination Period. Our partnership agreement, as amended, requires that we make distributions of available cash from operating surplus for any quarter in the following manner during the subordination period:

first, to QRE GP and common unitholders in accordance with their percentage interest until there has been distributed in respect of each common unit then outstanding an amount equal to the minimum quarterly distribution of $0.4125 per unit per whole quarter (or $1.65 per year);

second, to QRE GP and common unitholders in accordance with their percentage interest until there has been distributed in respect of each common unit then outstanding an amount equal to the cumulative common unit arrearage existing with respect to such quarter;

third, to QRE GP in accordance with its percentage interest and to the unitholders holding subordinated units, pro rata, a percentage equal to 100% less QRE GP’s percentage interest, until there has been distributed in respect of each subordinated unit then outstanding an amount equal to the minimum quarterly distribution for such quarter; and

thereafter, to QRE GP and all unitholders (other than preferred unitholders), pro rata.

After Subordination Period. Effective December 22, 2012 the subordinated period ended. As a result, each outstanding subordinated unit converted into one common unit and will participate pro rata with the other common units in distributions of available cash.

QRE GP Interest

QRE GP owns a 0.1% interest in us. This interest entitles QRE GP to receive distributions of available cash from operating surplus as discussed further below under Cash Distributions. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and QRE GP will receive.

QRE GP has sole responsibility for conducting our business and managing our operations. QRE GP’s board of directors and executive officers will make decisions on our behalf.

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Allocations of Net Income

Net income (loss) is reduced by noncontrolling interest and is then allocated to the preferred and Class B unitholders to the extent distributions are made or accrued to them during the period and to QRE GP to the extent of the management incentive fee. The remaining income is allocated between QRE GP and the common unitholders in proportion to their pro rata ownership during the period.

Cash Distributions

Our partnership agreement, as amended, requires that within 45 days after the end of each quarter, or at our general partner’s sole discretion, or in three equal installments within 15, 45, and 75 days following the end of each quarter, we distribute all of our available cash to preferred unitholders, in arrears, and common unitholders of record on the applicable record date, as determined by QRE GP.

Available cash, for any quarter prior to liquidation, consists of all cash on hand at the end of the quarter:

less the amount of cash reserves established by QRE GP to:

(i.)

provide for the proper conduct of our business;

(ii.)

comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation; and

(iii.)

provide funds for distribution to our unitholders and to QRE GP for any one or more of the next four quarters.

less, the aggregate Preferred Unit distribution accrued and payable for the quarter;

plus, if QRE GP so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter.

Commencing with the fourth quarter of 2013, we will distribute to common unitholders on a monthly basis.We intend to continue to make regular cash distributions to unitholders on a monthly or quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit facility prohibits us from making cash distributions if any potential default or event of default, as defined in our credit facility, occurs or would result from the cash distribution.

Our partnership agreement requires us to distribute all of our available cash on a monthly or quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. We intend to fund a portion of our capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.

As of December 31, 2013, QRE GP owns a 0.1% general partner interest in us, represented by 51,036 general partner units. QRE GP has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. QRE GP’s initial 0.1% interest in distributions will be reduced if we issue additional units in the future and QRE GP does not contribute a proportionate share of capital to us to maintain its 0.1% general partnership interest.

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The following table shows the cash distributions declared or paid to date:


										Limited Partners
												Affiliated
For the period ended		Distributions to Preferred Unitholders		Distributions per Preferred Unit(1)		General Partner		Class B		Public Common		Common		Subordinated		Total Distributions to Other Unitholders		Distributions per other units

December 31, 2011 (2)	$	3,424	$	0.21	$	16	$		$	8,344	$	5,368	$	3,393	$	17,121	$	0.4750
March 31, 2012 (2)		3,500		0.21		20				17,892		-		3,394		21,306		0.4750
June 30, 2012 (2)		3,500		0.21		20				18,584		-		3,484		22,088		0.4875
September 30, 2012 (2)		3,500		0.21		20				18,529		-		3,484		22,033		0.4875
December 31, 2012 (2)		3,500		0.21		25				25,275		3,484		-		28,784		0.4875
December 31, 2012 (3)		-		-		-		2,990		-		-		-		2,990		0.4875
March 31, 2013 (2)		3,500		0.21		25		2,990		25,480		3,484		-		31,979		0.4875
June 30, 2013 (2)		3,500		0.21		25		2,990		25,475		3,484		-		31,974		0.4875
September 30, 2013 (2)		3,500		0.21		25		2,881		25,465		3,484		-		31,855		0.4875
December 31, 2013 (2)		3,500		0.21		-		-		-		-		-		-		-
December 31, 2013 (4)		-		-		8		987		8,489		1,161		-		10,645		0.1625
December 31, 2013 (5)		-		-		8		997		8,489		1,161		-		10,655		0.1625
December 31, 2013 (6)						8		997		8,489		1,161		-		10,655		0.1625

⁽¹⁾

Preferred Units were prorated a quarterly distribution for the portion of the fourth quarter beginning on October 3, 2011 through December 31, 2011 in accordance with the Partnership Agreement.

⁽²⁾

Distributions were made within 45 days after the end of each quarter.

⁽³⁾

The December 31, 2012 and March 31, 2013 distributions to the Class B units were paid 45 days after the end of the first quarter 2013.

⁽⁴⁾

⁽⁵⁾

⁽⁶⁾

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NOTE 13 — NET INCOME (LOSS) PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income (loss) per limited partner unit for the years ended December 31, 2013, 2012 and 2011:


	Year Ended
	December 31, 2013		December 31, 2012		December 31, 2011
Net income	$	61,628	$	79,751	$	88,295
Net income (loss) attributable to noncontrolling interest		(663)		-		-
Net income (loss) attributable to QR Energy, LP		60,965		79,751		88,295
Net (income) loss attributable to predecessor operations		-		(37,350)		(76,249)
Distribution on Class C convertible preferred units		(14,000)		(14,000)		(3,424)
Amortization of preferred unit discount		(15,553)		(14,930)		(3,638)
Distribution on Class B units		(12,838)		-		-
Net income (loss) available to other unitholders		18,574		13,471		4,984
Less: general partner's interest in net income (loss)		3,391		6,149		1,575
Limited partner's interest in net income (loss)	$	15,183	$	7,322	$	3,409
Common unitholders' interest in net income (loss)	$	15,183	$	6,570	$	2,730
Subordinated unitholders' interest in net income (loss)	$	-	$	752	$	679
Net income (loss) attributable to QR Energy, LP per limited partner unit:
Common unitholders' (basic)	$	0.26	$	0.19	$	0.10
Common unitholders' (diluted)	$	0.26	$	0.19	$	0.10
Subordinated unitholders' (basic and diluted)	$	-	$	0.11	$	0.10
Weighted average number of limited partner units outstanding (in thousands):
Common units (basic)		58,524		35,132		28,728
Common units (diluted) (1) (2)		58,524		35,282		28,728
Subordinated units (basic and diluted)		-		6,970		7,146

⁽¹⁾

For the years ended December 31, 2013, 2012 and 2011, we had weighted average preferred units outstanding of 16,666,667, 16,666,667, and 4,109,589, respectively. For the years ended December 31, 2013, 2012 and 2011, we had 5,088,831, zero, and zero, respectively, of weighted average Class B units outstanding. The preferred and Class B units are contingently convertible into common units and could potentially dilute earnings per unit in the future. The preferred and Class B units have been excluded in the diluted earnings per unit calculation for the years ended December 31, 2013, 2012 and 2011 as they were antidilutive for the period.

⁽²⁾

In connection with the expiration of the subordination period on December 22, 2012, the general partner had the right to convert all or a portion of the fourth quarter management incentive fee into Class B common units. In 2012, we had weighted average Class B units of 150,896 which were contingently convertible. The Class B units were included in the 2012 diluted earnings per unit calculation as they were dilutive to the period.

Net income (loss) per limited partner unit is determined by dividing the limited partners’ interest in net income, and net income available to the common unitholders, by the weighted average number of limited partner units outstanding during the period.

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NOTE 14 — ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

Changes in accumulated other comprehensive income / (loss) by component, net of tax, were as follows:



		Gains/(loss) on
		Available-For-Sale		Postretirement
		Securities		Benefits		Total
Accumulated comprehensive income as of December 31, 2012	$	-	$	-	$	-
Other comprehensive income before reclassifications		631		4,061		4,692
Amounts reclassified from accumulated other comprehensive income (1)		(18)		-		(18)
Net current period other comprehensive income		613		4,061		4,674
Accumulated comprehensive income as of December 31, 2013	$	613	$	4,061	$	4,674

Accumulated comprehensive income attributable to non-controlling interest		273		1,657		1,930
Accumulated comprehensive income attributable to QR Energy, LP	$	340	$	2,404	$	2,744

⁽¹⁾

Amounts were reclassified from accumulated other comprehensive income / (loss) into “Other income (expense), net” in the Consolidated Statement of Operations.

NOTE 15 — EQUITY-BASED COMPENSATION

The QRE GP, LLC Long-Term Incentive Plan (the “Plan”) was established for employees, officers, consultants and directors of QRE GP and its affiliates, including QRM, who perform services for us. The Plan consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the Plan is to provide additional incentive compensation to such individuals providing services to us and to align the economic interests of such individuals with the interests of our unitholders. The Plan limits the number of common units that may be delivered pursuant to awards under the Plan to 1.8 million units.

On February 3, 2014 we filed a definitive proxy statement on Form 14/A, which provides information regarding a special meeting of limited partners to be held on March 10, 2014 to hold a unitholder vote on an amendment to our Long-Term Incentive Plan to increase the number of units under the plan by 3,000,000. See Note 22 – Subsequent Events.

Restricted Units

Periodically we issue restricted units with a service condition (“Restricted Units”) and restricted units with a market condition (“Performance Units”). The fair value of the Restricted Units, based on the closing price of our common units at the grant date, is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the Performance Units, based on a Monte Carlo model with assumptions based on market conditions, is amortized to compensation expense on a straight-line basis over the vesting period of the award.

On April 22, 2013, we granted approximately 455,000 Restricted Unit awards and approximately 149,000 Performance Unit awards to employees of QRM and 20,000 unit awards to independent directors of the Partnership.

Service Restricted Units

For the years ended December 31, 2013, 2012 and 2011, we recognized compensation expense related to the outstanding awards of $6.1 million, $3.1 million, and $1.4 million, respectively. As of December 31, 2013, we had 754,822 of Restricted Units outstanding with unrecognized grant date fair value compensation expense of $10.2 million, which we expect to be recognized over a weighted-average period of approximately 1.8 years. The amount of unrecognized compensation expense does not necessarily represent the amount that will ultimately be recognized by us in our statements of operations.

Performance Restricted Units.

F–39

The performance awards will be earned over a three year period based on the Partnership’s performance relative to its peers in accordance with the Plan. The final shares to be issued will range from 0 – 225% of the initial shares granted. For Performance Units, we recognize compensation expense using a straight-line amortization of the grant date fair value over the performance period. For the years ended December 31, 2013 and 2012, we recognized compensation expense related to the outstanding awards of $0.8 million and $0.2 million. As of December 31, 2013, we had 267,489 of Performance Units outstanding with unrecognized grant date fair value compensation expense of $1.7 million, which we expect to be recognized over a weighted-average period of approximately 1.8 years. The amount of unrecognized compensation expense does not necessarily represent the amount that will ultimately be recognized by us in our statements of operations.

The following assumptions were used for the Performance Units based on market conditions using a Monte Carlo model to estimate the grant date fair value of the awards. The four primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns, correlation in movement of total unitholder return relative to a relevant peer group and the expected distribution rate. Risk-free rate was based on the Federal Reserve for treasuries equal to the remaining duration of the performance period, which was 0.4% for the 2013 and 2012 grants. Volatility was determined based on the annualized daily historical volatility, which was approximately 29% for the 2013 grants and ranged from 31% to 32% for the 2012 grants. Correlation in movement of total unitholder return was determined based on a correlation matrix that was created which identifies total shareholder return correlations for each pair of companies in the peer group, including the Partnership. The paired returns in the correlation matrix ranged from 33.7% to 56.6% for the Partnership and its peer group. The expected distribution rate is calculated using a trailing six month average for the Partnership and its peer group as of the date of grant, which was 11% and 10% for the 2013 and 2012 grants. Based on these inputs discussed above, a ranking was projected identifying the Partnership's rank relative to the peer group for each award period which determines the anticipated payout. The weighted average grant date fair value per unit, using the method described above, was $10.03 and $10.35 for the years ended December 31, 2013 and 2012, respectively, and is being recognized ratably in expense over the service period.

Unit-Based Awards Activity

The following table summarizes the Partnership’s unit-based awards for the years ended December 31, 2013, 2012 and 2011, (in thousands, except per unit amounts):


	Number of			Number of
	Unvested	Weighted		Unvested	Weighted
	Service	Average		Performance	Average
	Restricted	Grant-Date		Restricted	Grant-Date
	Units	Fair Value		Units	Fair Value
Unvested units, December 31, 2010	148,160	$	20.03	-	$	-
Granted	214,588		20.51	-		-
Forfeited	(38,586)		20.75	-		-
Vested	(52,798)		20.31	-		-
Unvested units, December 31, 2011	271,364	$	20.26	-	$	-
Granted	437,211		18.22	121,137		10.35
Forfeited	(61,444)		19.47	(3,055)		10.45
Vested	(96,890)		20.05	-		-
Unvested units, December 31, 2012	550,241	$	18.80	118,082	$	10.34
Granted	491,847		17.97	149,407		10.03
Forfeited	(68,806)		18.41	-		-
Vested	(218,460)		19.01	-		-
Unvested units, December 31, 2013	754,822	$	18.22	267,489	$	10.17

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NOTE 16 — ACCRUED AND OTHER LIABILITIES

As of December 31, 2013 and December 31, 2012 we had the following accrued and other liabilities:


	December 31, 2013		December 31, 2012
Accrued lease operating expenses	$	20,297	$	11,173
Accrued capital spending		16,316		6,109
Distributions payable (1)		14,155		3,500
Senior notes accrued interest		11,563		11,563
Accrued production and other taxes		6,270		7,401
Gas imbalance liability (2)		6,214		5,351
Other		4,230		1,187
	$	79,045	$	46,284

⁽¹⁾

For the year ended December 31, 2013 and 2012, balance includes preferred distributions payable to affiliates of $3.5 million.

⁽²⁾

We account for our natural gas imbalances under the sales method. We had overproduced liabilities of $6.2 million and $5.4 million included in accrued liabilities on our consolidated balance sheets as of December 31, 2013 and December 31, 2012, respectively, for overproduced positions which were beyond ultimate recoverability of remaining natural gas reserves. As of December 31, 2013, our gross underproduced natural gas position was approximately $4.1 million (1.5 MMcf) and our gross overproduced natural gas position was approximately $6.2 million (2.1 MMcf). These gross positions were valued at $4.62 per Mcf for underproduced natural gas positions and $4.31 per Mcf for overproduced natural gas positions without regard to remaining natural gas reserves. As of December 31, 2012, our gross underproduced natural gas position was approximately $1.2 million (1.5 MMcf) and our gross overproduced natural gas position was approximately $5.4 million (2.1 MMcf). These gross positions were valued at $3.46 per Mcf for underproduced natural gas positions and $3.41 per Mcf for overproduced natural gas positions without regard to remaining natural gas reserves.

NOTE 17 — SIGNIFICANT CUSTOMERS

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



	December 31, 2013		December 31, 2012		December 31, 2011
Customer A	27	%	33	%	29	%
Customer B	21	%	13	%	(1)
Customer C	17	%	(1)		(1)
Customer D	(1)		12	%	11	%
Customer E	(1)		(1)		12	%

⁽¹⁾

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

Because there are numerous other parties available to purchase our oil and gas production, we believe that the loss of any individual purchaser would not materially affect our ability to sell our natural gas or crude oil production.

NOTE 18 — INCOME TAXES

Our wholly owned subsidiaries are treated as partnerships for federal income tax purposes but are subject to Texas margin taxes. Our controlling interest in a privately held C-Corp is subject to federal income tax. We recorded a deferred tax asset of $1.1 million and $0.3 million related to our operations located in Texas as of December 31, 2013 and 2012 and a deferred tax liability of $3.2 million and $0.4 million as of December 31, 2013 and 2012. The deferred tax asset and deferred tax liability are presented net as a deferred tax liability of $2.1 million on the consolidated balance sheet as of December 31, 2013 and as a deferred tax liability of $0.1 million on the consolidated balance sheet as of December 31, 2012. Our provision for income taxes was a net benefit of $0.4 million and a net expense of $0.5 million and $0.9 million for years ended December 31, 2013, 2012 and 2011.

F–41

Income tax expense (benefit) is summarized as follows:


	December 31, 2013		December 31, 2012		December 31, 2011
Current	$		$		$
Federal		17		-		-
State		(66)		156		1
Total		(49)		156		1

Deferred
Federal		(202)		-		-
State		(102)		372		849
Total		(304)		372		849

Total expense income tax (benefit)		(353)		528		850

Federal income tax expense (benefit) differs from expected tax expense (computed by applying the statutory federal income tax rate of 34% to income (loss) before income taxes) as follows:


	December 31, 2013			December 31, 2012			December 31, 2011
Computed expected tax rate		34.00	%		34.00	%		34.00	%
Tax adjustment for partnership income		(33.55)	%		(34.00)	%		(34.00)	%
Change in valuation allowance		(0.32)	%		-	%		-	%
Other		(0.69)	%		0.66	%		0.95	%
		(0.56)	%		0.66	%		0.95	%

The tax effects of temporary differences and net operating losses that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2013 and 2012 are as follows:


	December 31, 2013		December 31, 2012
Deferred Tax Assets	$		$
Asset retirement obligation		1,740		-
Post-retirement benefit costs		845		-
Net operating losses		2,043		-
Other		-		300
Total deferred tax assets		4,628		300
Valuation allowance		(3,582)		-
Net deferred tax assets		1,046		300

Deferred Tax Liabilities
Unrealized gain on investments		223		-
Depreciation		1,847		-
Pension costs		1,031		-
Other		59		402
Total deferred tax liabilities		3,160		402

Net Deferred Tax Asset (Liability)		(2,114)		(102)

As of December 31, 2013, the total NOL carryforward consists of $6 million of federal NOL carryforwards, which expire between 2026 and 2030. The Partnership has not fully recognized the deferred tax assets for certain items in advance of their deductibility for income tax purposes due to the uncertainty of realization. The benefit of these items will be recognized in future years to the extent that such deductions are used to reduce taxable income.

As of December 31, 2013, we have not identified any uncertain tax provisions.

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NOTE 19 — RELATED PARTY TRANSACTIONS

Ownership in QRE GP by the Management of the Fund and its Affiliates

As of December 31, 2013, affiliates of the Fund owned 100% of QRE GP, and an aggregate 29.2% limited partner interest in us represented by all of our preferred units and 7,145,866 common units. In addition, QRE GP owned a 0.1% general partner interest in us, represented by 51,036 general partner units and a 7.5% limited partner interest represented by 6,133,558 Class B units. Our Chief Executive Officer and Chief Operating Officer have a beneficial ownership in QRE GP and the Fund.

As of December 31, 2012, affiliates of the Fund owned 100% of QRE GP, and an aggregate 31.7% limited partner interest in us represented by all of our preferred units and 7,145,866 common units. In addition, QRE GP owned a 0.1% general partner interest in us, represented by 51,036 general partner units. Our Chief Executive Officer and Chief Operating Officer have a beneficial ownership in QRE GP and the Fund.

Contracts with QRE GP and Its Affiliates

We have entered into agreements with QRE GP and its affiliates. The following is a description of those agreements.

Services Agreement

On December 22, 2010, in connection with the closing of the IPO, we entered into the Services Agreement with QRM, QRE GP and OLLC, pursuant to which QRM will provide the administrative and acquisition advisory services necessary to allow QRE GP to manage, operate and grow our business. We do not have any employees. The Services Agreement requires that employees of QRM (including the persons who are executive officers of QRE GP) devote such portion of their time as may be reasonable and necessary for the operation of our business. The executive officers of QRE GP currently devote a majority of their time to our business, and we expect them to continue to do so for the foreseeable future.

Under the Services Agreement, from the closing of the IPO through December 31, 2012, QRM was entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined by the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee.

Beginning on January 1, 2013, QRM became 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 included 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 raises a second fund, the quarterly administrative services costs will be further divided to include 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 the years ended December 31, 2013, 2012 and 2011, the Fund charged us $33 million, $7.3 million, and $2.5 million, respectively, in administrative services fee in accordance with the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM.

F–43

In connection with the management of our business, QRM provides services for invoicing and collecting of our revenues as well as processing of payments to our vendors. Periodically QRM remits cash to us for the net working capital received on our behalf. Changes in the affiliate (payable)/receivable balances during the years ended December 31, 2013 and 2012 are included below:


Net affiliate payable as of December 31, 2011	$	3,734
Revenues and other increases		256,496
Expenditures		(208,780)
Settlements from the Fund		(51,450)
Net affiliate receivable as of December 31, 2012		-
Revenues and other increases		403,867
Expenditures		(264,092)
Settlements from the Fund		(135,860)
Net affiliate receivable as of December 31, 2013	$	3,915

Other Contributions to Partners’ Capital

Other contributions to partners’ capital include the following items for the period indicated:


	Year Ended		Year Ended		Year Ended
	December 31, 2013		December 31, 2012		December 31, 2011
Noncash general and administrative expense contributed by the Fund(1)	$	-	$	31,591	$	17,364
Noncash general and administrative expense contributed by the Predecessor(2)		-		6,485		17,357
Fair value of interest rate derivatives novated to us from the Fund(3)		-		-		2,600
Prepaid insurance incurred by the Fund on our behalf(4)		-		-		224
Total other contributions from affiliates	$	-	$	38,076	$	37,545

⁽¹⁾

Represents our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us.

⁽²⁾

Represents our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us for the December 2012 Transferred Properties for the years ended December 31, 2012 and 2011 and for the October 2011 Transferred Properties for the period from January 1 to September 30, 2011.

⁽³⁾

On February 28, 2011, the Fund novated to us fixed-for-floating interest rate swaps covering $225.0 million of borrowings under our revolving credit facility. The Fund also novated to us on July 1, 2011 natural gas basis swaps with contract dates until 2015. The fair value of these derivative instruments was a net asset position.

⁽⁴⁾

QRM also incurred prepaid insurance on our behalf, but not reimbursable by us.

Cash Contributions from the Predecessor

The following table presents cash received by the Predecessor on our behalf related to the December 2012 Transferred Properties and October 2011 Transferred Properties for the following periods prior to our acquisition of the net assets on December 28, 2012 and October 3, 2011, respectively:



	Year ended		Year ended
	December 31, 2012		December 31, 2011
Cash receipts	$	(109,274)	$	(204,898)
Production expenditures paid		41,528		80,889
Derivative buyup payment		-		42,653
Interest paid		4,050		9,981
Capital expenditures paid		28,723		45,868
Cash distributions to the Predecessor	$	(34,973)	$	(25,507)

F–44

Omnibus Agreement

On December 22, 2010, in connection with the closing of our IPO, we entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among us, QRE GP, OLLC, the Fund, the Predecessor and QA Global.

Under the terms of the Omnibus Agreement, the Fund will offer us the first option to purchase properties that it may offer for sale, so long as the properties consist of at least 70% proved developed producing reserves. The 70% threshold is a value-weighted determination made by the Fund. Additionally, the Fund will allow us to participate in acquisition opportunities to the extent that it invests any of the remaining approximately $113.2 million of its equity capital or acquires reserves as follow-on investments that are associated with its existing reserves. Specifically, the Fund will offer us the first opportunity to participate in at least 25% of each acquisition opportunity available to it, so long as at least 70% of the allocated value is attributable to proved developed producing reserves. These contractual obligations will remain in effect until December 21, 2015.

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

Management Incentive Fee

Under our partnership agreement, for each quarter for which we have paid distributions that equaled or exceeded 115% of our minimum quarterly distribution (which amount we refer to as our “Target Distribution”), or $0.4744 per unit, QRE GP will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of our management incentive fee base, which will be an amount equal to the sum of:

the future net revenue of our estimated proved oil and natural gas reserves, discounted to present value at 10% per annum and calculated based on SEC methodology;

adjusted for our commodity derivative contracts; and

the fair market value of our assets, other than our estimated oil and natural gas reserves and our commodity derivative contracts, that principally produce qualifying income for federal income tax purposes, at such value as may be determined by the board of directors of QRE GP and approved by the conflicts committee of QRE GP’s board of directors.

For the years ended December 31, 2013, 2012 and 2011, the management incentive fee earned by QRE GP was $3.4 million, $6.1 million and $1.6 million, respectively. The fourth quarter 2012 management incentive fee was reduced by the portion of the management incentive fee converted as discussed below under General Partner’s Right to Convert Management Incentive Fee into Class B Units.

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

From and after the end of the subordination period and subject to the limitations described below, our general partner has the continuing right, at any time when it has received all or any portion of the management incentive fee for three full consecutive quarters and shall be entitled to receive all or a portion of the management incentive fee for a fourth consecutive quarter, to convert into Class B units up to 80%, such percentage actually converted being referred to as the Applicable Conversion Percentage, of the management incentive fee for the fourth quarter in lieu of receiving a cash payment for such portion of the management incentive fee. Any Conversion Election made during a quarter must be made before payment of the management incentive fee in respect of the previous quarter and will be effective as of the first day of such quarter, and the Class B units issued upon such conversion will be entitled to distributions as if they were outstanding on the first day of such quarter.

The number of Class B units (rounded to the nearest whole number) to be issued in connection with such a conversion will be equal to (a) the product of: (i) the Applicable Conversion Percentage; and (ii) the average of the

F–45

management incentive fee paid to our general partner for the quarter immediately preceding the quarter for which such fee is to be converted and the management incentive fee payable to our general partner for the quarter for which such fee is to be converted, divided by (b) the cash distribution per unit for the most recently completed quarter.

We refer to such conversion as a “Conversion Election.” The reduction in the management incentive fee as a result of any conversion will directly offset the increase in distributions required by the newly issued Class B units.

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

The subordination period on our subordinated units ended on December 31, 2012 and our general partner had received a management incentive fee for three full consecutive quarters. On February 22, 2013, our general partner elected to convert 80% of the fourth quarter 2012 management incentive fee and, on March 4, 2013, received 6,133,558 Class B units which were issued and outstanding upon conversion. The general partner received a reduced fourth quarter management incentive fee of $0.7 million and received a distribution on the Class B units related to the fourth quarter 2012.

On March 2, 2014 we completed a transaction related to our general partner interest pursuant to a Contribution Agreement. See Note 22 – Subsequent Events for more information.

Purchase and Sale Agreements

On December 28, 2012, we completed an acquisition of certain oil and gas properties in Florida from the Fund for an aggregate price of $143.6 million, pursuant to the December 2012 Purchase Agreement. In exchange for the assets, we assumed $115.0 million in debt from the Fund and paid the remaining $28.6 million in cash.

On October 3, 2011, we completed an acquisition of certain oil and gas properties located in the Permian Basin, Ark-La-Tex and Mid-Continent areas from the Fund for an aggregate purchase price of $578.8 million, pursuant to a Purchase and Sale Agreement (the “October 2011 Purchase Agreement”) dated September 12, 2011. In exchange for the assets, we assumed $227.0 million in debt from the Fund which was repaid at closing and issued to the Fund 16,666,667 unregistered Preferred Units.

See Note 1 – Organization and Operations and Note 4 – Acquisitions for further discussion of the acquisitions and Note 2 – Summary of Significant Accounting Policies for discussion of the basis of presentation in the financial statements.

Lease Guarantees

The Fund has entered into various lease contracts that can routinely extend beyond five years which list the Partnership as a guarantor. See Note 11 – Commitments and Contingencies.

Long–Term Incentive Plan

On December 22, 2010, in connection with the closing of the IPO, the Board of Directors of QRE GP adopted the Plan to compensate employees, officers, consultants and directors of QRE GP and those of its affiliates, including QRM, who perform services for us. As of December 31, 2013, 2012 and 2011, we had 1,022,311, 668,323, and 271,364 unvested restricted and performance unit awards outstanding with remaining unamortized costs of $11.9 million, $9.0 million, and $4.8 million, respectively. For additional discussion regarding the Plan see Note 15 – Equity-Based Compensation.

Distributions of Available Cash to QRE GP and Affiliates

We will generally make cash distributions to our unitholders and QRE GP pro rata, including QRE GP and our affiliates. The Partnership made cash distributions to QRE GP and our affiliates during 2012 and 2013 as discussed in Note 12 – Partners’ Capital.

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Our Relationship with Bank of America

Don Powell, one of our independent directors, served as an independent director of Bank of America (“BOA”) through May 2013 and did not seek re-election. BOA is a lender under our Credit Agreement.

Farmout Agreement with Related Party

In January 2014, we entered into a Farmout Agreement with Tanos Exploration II, LLC (“Tanos”), a Quantum Energy Partners affiliate, whereas Tanos is to be the operator of certain wells until completion or other termination criteria are met.

NOTE 20 – SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information was as follows for the periods indicated:


	Year Ended		Year Ended		Year Ended
	December 31,		December 31,		December 31,
	2013		2012		2011
Supplemental Cash Flow Information
Cash paid during the period for interest	$	46,504	$	41,040	$	22,465
Cash paid for income tax		-		18		-
Non-cash Investing and Financing Activities
Non-cash consideration paid for transferred properties from the Fund	$	-	$	-	$	(354,500)
Excess consideration of fair value of transferred properties from the Fund		-		68,861		102,454
Change in accrued capital expenditures		(10,207)		(3,481)		9,551
Insurance premium financed		-		-		224
Receivable from QRE GP in connection with equity issuance		(165)		157		-
Interest rate swaps novated from the Fund		-		-		2,600
Accrued distributions		(14,155)		(3,500)		(20,545)
General and administrative expense allocated from the Fund		-		38,076		34,721
Management incentive fee accrued		-		-		(1,572)
Amortization of increasing rate distributions(1)		15,553		14,930		3,638

⁽¹⁾

Amortization of increasing rate distributions is offset in the preferred unitholders’ capital account by a non-cash distribution.

NOTE 21 – SUBSIDIARY GUARANTORS

The Senior Notes, issued on July 30, 2012 by the Partnership and QRE FC (the “Subsidiary Co-Issuer”), are guaranteed by OLLC, a 100% owned subsidiary of the Partnership (the “Guarantor”), and may be guaranteed by certain other future subsidiaries. The Guarantor is 100% owned by the Partnership and its guarantee of the Senior Notes is full and unconditional. The Partnership has no assets or operations independent of its subsidiaries and there are no significant restrictions upon the ability of the Guarantor to distribute funds to the Partnership. The guarantee constitutes a joint and several obligation with any additional future guarantees. The Partnership’s only other subsidiary is ETSWDC, which does not guarantee the Senior Notes (the “Non-Guarantor”). Refer to Note 10 – Long-Term Debt for details on the conditions under which guarantees of the Senior Notes may be released. ETSWDC is a non-minor subsidiary and we are providing condensed consolidated financial statements prospectively in accordance with SEC regulations.

The following condensed consolidated financial information is presented in accordance with Rule 3-10 of the Securities and Exchange Commission’s Regulation S-X, and uses the same accounting policies used to prepare the financial information located elsewhere in our consolidated financial statements and related footnotes.

F–47



Condensed Consolidating Balance Sheets
	December 31, 2013
		Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations		Consolidated
Assets
Current assets
Cash	$	78	$	-	$	10,575	$	2,707	$	-	$	13,360
Accounts receivable		-		-		55,073		2,939		(570)		57,442
Due from affiliates		234,746		-		-		-		(230,831)		3,915
Derivative instruments		-		-		27,485		-		-		27,485
Prepaid and other current assets		-		-		1,718		141		-		1,859
Total current assets		234,824		-		94,851		5,787		(231,401)		104,061
Noncurrent assets
Oil and natural gas properties and other property and equipment, net		-		-		1,591,015		13,968		-		1,604,983
Derivative instruments		-		-		62,131		-		-		62,131
Investment in subsidiaries		711,734		-		16,478		-		(728,212)		-
Other assets		4,663		-		20,176		19,913		-		44,752
Total noncurrent assets		716,397		-		1,689,800		33,881		(728,212)		1,711,866
Total assets	$	951,221	$	-	$	1,784,651	$	39,668	$	(959,613)	$	1,815,927

Liabilities and Partners' Capital
Current liabilities
Current portions of asset retirement obligations	$	-	$	-	$	4,310	$	-	$	-	$	4,310
Due to affiliates		-		-		230,831		-		(230,831)		-
Derivative instruments		-		-		11,233		-		-		11,233
Accrued and other liabilities		25,718		-		52,100		1,797		(570)		79,045
Total current liabilities		25,718		-		298,474		1,797		(231,401)		94,588
Noncurrent liabilities
Long-term debt		296,593		-		615,000		-		-		911,593
Derivative instruments		-		-		6,251		-		-		6,251
Asset retirement obligations		-		-		145,893		5,118		-		151,011
Other liabilities		-		-		7,299		7,726		-		15,025
Total noncurrent liabilities		296,593		-		774,443		12,844		-		1,083,880
Partners' capital
QR Energy, LP partners' capital		628,910		-		711,734		25,027		(736,761)		628,910
Noncontrolling interest		-		-		-		-		8,549		8,549
Total partners' capital		628,910		-		711,734		25,027		(728,212)		637,459
Total liabilities and partners' capital	$	951,221	$	-	$	1,784,651	$	39,668	$	(959,613)	$	1,815,927



Condensed Consolidating Statements of Operations

		Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations		Consolidated
Year Ended December 31, 2013
Total revenues	$	-	$	-	$	447,077	$	10,262	$	(1,710)	$	455,629
Expenses
Production and disposal and related expenses		-		-		172,998		9,410		(1,710)		180,698
Depreciation, depletion and amortization		-		-		115,039		145		-		115,184
General and administrative		7,101		-		34,800		-		-		41,901
Accretion of asset retirement obligations and acquisition and transaction costs		-		-		8,831		112		-		8,943
Total expenses		7,101		-		331,668		9,667		(1,710)		346,726
Operating income		(7,101)		-		115,409		595		-		108,903
Gain (loss) on commodity derivative contracts, net		-		-		(1,217)		-		-		(1,217)
Interest expense, net, income tax expense and other income, net		(29,468)		-		(17,574)		984		-		(46,058)
Equity in earnings		97,534		-		916		-		(98,450)		-
Net (loss) income		60,965		-		97,534		1,579		(98,450)		61,628
Less: Net income attributable to noncontrolling interest		-		-		-		-		663		663
Net income (loss) attributable to QR Energy, LP	$	60,965	$	-	$	97,534	$	1,579	$	(99,113)	$	60,965

F–48


Condensed Consolidating Statements of Comprehensive Income

		Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations		Consolidated
Year Ended December 31, 2013
Net income (loss)	$	60,965	$	-	$	97,534	$	1,579	$	(98,450)	$	61,628
Other comprehensive income, net of tax:
Reclassification adjustment for available-for-sale securities								(18)				(18)
Change in fair value of available-for-sale securities		340		-		340		631		(680)		631
Pension and postretirement benefit:
Actuarial gain		2,404				2,404		4,061		(4,808)		4,061
Total other comprehensive income		2,744		-		2,744		4,674		(5,488)		4,674
Total comprehensive income (loss)		63,709		-		100,278		6,253		(103,938)		66,302
Less: Comprehensive income attributable to noncontrolling interest		-		-		-		-		2,593		2,593
Comprehensive income (loss) attributable to QR Energy, LP	$	63,709	$	-	$	100,278	$	6,253	$	(106,531)	$	63,709



Condensed Consolidating Statements of Cash Flows

		Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations		Consolidated
Year Ended December 31, 2013
Net cash (used in) provided by operating activities	$	(22,103)	$	-	$	222,997	$	1,251	$	-	$	202,145
Cash flows from investing activities
Additions to oil and natural gas properties		-		-		(87,936)		(311)		-		(88,247)
Acquisitions		-		-		(131,715)		3,481		-		(128,234)
Distributions from subsidiaries		167,470		-		-		-		(167,470)		-
Proceeds from sale of available-for-sale securities		-		-		-		8,535		-		8,535
Purchases of available-for-sale securities		-		-		-		(10,249)		-		(10,249)
Net cash (used in) provided by investing activities		167,470		-		(219,651)		1,456		(167,470)		(218,195)
Cash flows from financing activities
Distributions to unitholders		(141,582)		-		-				-		(141,582)
Proceeds from bank borrowings		-		-		180,000		-		-		180,000
Repayments on bank/intercompany borrowings		-		-		(35,000)		-		-		(35,000)
Distributions to Parent		-		-		(167,470)		-		167,470		-
Other		(3,775)		-		(2,069)		-		-		(5,844)
Net cash (used in) provided by financing activities		(145,357)		-		(24,539)		-		167,470		(2,426)
Net increase (decrease) in cash		10		-		(21,193)		2,707		-		(18,476)
Cash at beginning of period		68		-		31,768		-		-		31,836
Cash at end of period	$	78	$	-	$	10,575	$	2,707	$	-	$	13,360

NOTE 22 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after December 31, 2013, up until the issuance of the financial statements.

On January 31, 2014, we closed the acquisition of primarily natural gas properties located in East Texas from a private seller for $36.0 million in cash, subject to customary purchase price adjustments, using funds drawn on our revolving credit facility.

On February 3, 2014, we filed a definitive proxy statement on Form 14/A, which provides information regarding a special meeting of limited partners to be held on March 10, 2014 to hold a unitholder vote on an amendment to our Long-Term Incentive Plan to increase the number of units under the plan by 3,000,000.

On February 20, 2014, we entered into a purchase and sale agreement of primarily oil properties located in East Texas from a private seller for $11.1 million, subject to customary purchase price adjustments.

F–49

Effective March 2, 2014, we entered into the sixth amendment to the Credit Agreement, which permits the GP Buyout Transaction.

On March 3, 2014, we filed a prospectus supplement establishing an at-the-market equity program under which the Company may sell common units with an aggregate offering price up to $100 million, from time to time, until the expiration of QR Energy’s shelf filing in June 2015.

On January 24, 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in February 2014 to the unitholders of record as of February 10, 2014.

On February 28, 2014, the Board of Directors approved the third monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 and will be paid in March 2014 to the unitholders of record as of March 10, 2014. As a result of this declaration, a management incentive fee related to the fourth quarter 2013 in the amount of $1.3 million will be recognized during the three months ended March 31, 2014.

F–50

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Capitalized Costs

The following table sets forth the capitalized costs related to our oil and natural gas producing activities as of the dates indicated:


		December 31,
	2013		2012
Evaluated oil and natural gas properties	$	1,905,110	$	1,656,146
Unevaluated oil and natural gas properties		4,320		11,500
Gross oil and natural gas properties		1,909,430		1,667,646
Accumulated depreciation, depletion and amortization		(318,415)		(203,377)
Net capitalized costs	$	1,591,015	$	1,464,269

Pursuant to the FASB’s authoritative guidance on asset retirement obligations, net capitalized costs include asset retirement costs of $125.9 million and $104.2 million as of December 31, 2013 and 2012.

Costs Incurred

Our oil and natural gas activities are conducted in the United States. The following table summarizes the costs incurred by us for the periods indicated:



	Year Ended December 31,
	2013		2012			2011
Acquisition of oil and natural gas properties:
Evaluated	$	128,234	$	442,363	$	-
Unevaluated		-		11,500		-
Development costs		98,142		140,037		102,606
Total	$	226,376	$	593,900	$	102,606

Estimated Proved Reserves

Third Party Reserves Estimate. The reserve estimates as of December 31, 2013, 2012 and 2011 presented in the table below were based on reserve reports prepared by Netherland, Sewell & Associates, Inc. for 2013 and Miller & Lents, Ltd. for 2012 and 2011, independent reserve engineers, using FASB and SEC rules in effect as of December 31, 2013, 2012 and 2011.

Oil and Natural Gas Reserve Quantities. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made.

Prices include consideration of changes in existing prices provided only by contractual arrangement, but not on escalations based on future conditions. All of the Partnership’s oil and natural gas producing activities were conducted within the continental United States.

Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as “proved developed reserves” only after testing by a pilot project or after the operations of an installed program has confirmed through production response that the increased recovery will be achieved.

We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

F–51

Following is a summary of the proved developed and total proved oil, natural gas and NGL reserves attributed to our operations for the periods indicated:


		Natural
	Oil	Gas	NGL	Total
	(MBbl)	(MMcf)	(MBbl)	(MBoe)

Balance, December 31, 2010	36,161	243,265	1,920	78,625
Extensions	2,002	677	211	2,325
Revisions of previous estimates	4,033	(28,461)	6,873	6,162
Production	(2,594)	(16,927)	(377)	(5,792)
Balance, December 31, 2011	39,602	198,554	8,627	81,320
Extensions	1,877	4,958	257	2,960
Revisions of previous estimates	342	(12,643)	1,764	(1)
Acquisition of reserves	18,123	12,926	647	20,924
Production	(3,106)	(13,475)	(743)	(6,095)
Balance, December 31, 2012	56,838	190,320	10,552	99,110
Extensions	4,342	2,912	616	5,443
Revisions of previous estimates	8,429	(29,997)	241	3,671
Acquisition of reserves	7,229	3	163	7,393
Production	(3,823)	(11,497)	(796)	(6,535)
Balance, December 31, 2013	73,015	151,741	10,776	109,081

Proved developed reserves:
December 31, 2011	26,649	142,428	6,842	57,229
December 31, 2012	44,487	131,700	8,125	74,562
December 31, 2013	61,492	130,201	9,505	92,696
Proved undeveloped reserves:
December 31, 2011	12,953	56,126	1,785	24,092
December 31, 2012	12,351	58,620	2,427	24,549
December 31, 2013	11,524	21,540	1,272	16,385

Our total proved reserves have increased each year since 2010. The extensions in our reserves during 2013 are primarily attributable to additional development opportunities at Jay Field resulting from updated technical analysis. The revisions in our reserves during 2013 are primarily attributable to favorable prices and enhanced performance partially offset by a reduction in PUD reserves. The acquisitions of our reserves are primarily due to the 2013 East Texas Oil Field acquisition.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day of-the-month prices for the prior 12 months were $96.91/Bbl for oil and $3.67/MMbtu for natural gas as of December 31, 2013; $94.71/Bbl for oil and $2.76/MMbtu for natural gas as of December 31, 2012; and $96.19/Bbl for oil and $4.12/MMbtu for natural gas as of December 31, 2011. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2013, the relevant average realized prices for oil, natural gas and NGLs were $101.75 per Bbl, $3.60 per Mcf and $40.36 per Bbl. As of December 31, 2012, the relevant average realized prices for oil, natural gas and NGLs were $96.86 per Bbl, $2.81 per Mcf and $42.16 per Bbl. As of December 31, 2011, the relevant average realized prices for oil, natural gas and NGLs were $93.69 per Bbl, $4.28 per Mcf and $50.00 per Bbl.

Changes in the demand for oil and natural gas, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of current market value of our proved reserves.

F–52

The estimated standardized measure of discounted future net cash flows relating to our proved reserves is shown below for the periods indicated:


	Year Ended December 31,
	2013		2012		2011
Future cash inflows	$	8,264,552	$	6,429,372	$	4,992,358
Future production and development costs		(4,108,224)		(3,199,516)		(2,383,342)
Future net cash flows		4,156,328		3,229,856		2,609,016
10% annual discount for estimated timing
of cash flows		(2,112,944)		(1,623,015)		(1,297,353)
Standardized measure of discounted future
net cash flows	$	2,043,384	$	1,606,841	$	1,311,663

The above table does not include the effects of income taxes on future net revenues because during years ended December 31, 2013, 2012 and 2011, we were not subject to federal taxation at an entity-level. Accordingly, no provision for federal tax has been provided because taxable income is passed through to the partners. State corporate income, franchise and/or gross margins taxes have not been included due to their immateriality.

The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to our proved oil, natural gas and NGL reserves for the periods indicated:


	Year Ended December 31,
	2013		2012		2011
Beginning of period	$	1,606,841	$	1,311,663	$	1,050,024
Extensions		171,240		37,262		42,940
Revisions of previous estimates		67,569		(29)		114,354
Acquisition of reserves		170,811		484,163		-
Changes in future development costs, net		38,493		(49,392)		(59,955)
Development costs incurred during the year
that reduce future development costs		12,146		24,352		11,994
Net change in prices		121,459		(113,366)		261,402
Sales, net of production costs		(272,700)		(228,039)		(224,012)
Changes in timing and other		(33,159)		9,061		9,914
Accretion of discount		160,684		131,166		105,002
End of period	$	2,043,384	$	1,606,841	$	1,311,663

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly financial data was as follows for the periods indicated:


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
2013
Revenues	$	104,886	$	105,430	$	126,007	$	119,306
Gross profit (1)		62,138		62,941		78,751		71,101
Operating income		18,934		24,363		37,173		28,433
Net income (loss)		(8,174)		63,614		(21,497)		27,685
Net income (loss) attributable to QR Energy, LP		(8,174)		63,614		(21,719)		27,244
Net income (loss) per limited partner unit (basic)	$	(0.33)	$	0.89	$	(0.57)	$	0.25
Net income (loss) per limited partner unit (diluted)	$	(0.33)	$	0.77	$	(0.57)	$	0.25

(1) Represents total revenues less production expenses and disposal and related operating expenses.

F–53


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
2012
Revenues	$	94,104	$	89,356	$	91,128	$	97,410
Gross profit (1)		61,337		53,212		55,980		57,531
Operating income		25,656		15,409		17,222		12,054
Net income (loss)		(8,226)		130,700		(44,660)		1,937
Net income (loss) per limited partner unit (basic)	$	(0.49)	$	2.15	$	(1.25)	$	(0.24)
Net income (loss) per limited partner unit (diluted)	$	(0.49)	$	1.67	$	(1.25)	$	(0.24)

⁽¹⁾

Represents total revenues less production expenses.

F–54

F–55


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)


Large accelerated filer ☑	Accelerated filer ¨
Non-accelerated filer ¨	Smaller reporting company ¨