UNITED STATES SECURITIES AND EXCHANGE COMMISSION


Washington, D.C. 20549





Form 10–K





þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934





For the fiscal year ended December 31, 2010





OR





 ̈ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934





Commission File Number001-35010





QR ENERGY, LP


(Exact name of registrant as specified in its charter)





Delaware

(State or 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)





Registrant’s telephone number, including area code:(713) 452-2200





Securities registered pursuant to Section 12(b) of the Act:





Common Units Representing Limited Partner Interests

(Title of each class)

New York Stock Exchange

(Name of each exchange on which registered)





Securities registered pursuant to Section 12(g) of the Act:   None





Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. YES  ̈   NO  þ




Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES  ̈   NO þ




Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES  ̈  NO þ




Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES  ̈   NO  ̈





Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or any amendment to the Form 10–K.   þ





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





Large accelerated filer  ̈

Accelerated filer  ̈Non-accelerated filer  þ

Smaller reporting company  ̈





Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act).


YES  ̈ NO þ





As of June 30, 2010, the last business day of the registrant's most recently completed second fiscal quarter, the registrant's equity was not listed on any domestic exchange or over-the-counter market. The registrant's common units began trading on the New York Stock Exchange on December 17, 2010.





As of April 15, 2011, the registrant had 28,547,737 common units, 7,145,866 subordinated units and 35,729 general partner units outstanding.










TABLE OF CONTENTSPART IItem 1.
Business
9Item 1A.
Risk Factors
25Item 1B.
Unresolved Staff Comments
55Item 2.
Properties
55Item 3.
Legal Proceedings
55Item 4.
(Removed and Reserved)
55PART IIItem 5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
56Item 6.
Selected Financial Data
59Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
62Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
78Item 8.
Financial Statements and Supplementary Data
80Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
80Item 9A.
Controls and Procedures
80Item 9B.
Other Information
81PART IIIItem 10.
Directors, Executive Officers and Corporate Governance
82Item 11.
Executive Compensation
87Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
94Item 13.
Certain Relationships and Related Transactions, and Director Independence
95Item 14.
Principal Accounting Fees and Services
97PART IVItem 15.
Exhibits, Financial Statement Schedules
98Signatures
99
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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.





Developmentcosts:  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;




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·
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:The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.





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.




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





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





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.




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MMBtu:  One million British thermal units.





MMcf:  One thousand Mcf.





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





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.




Novation:




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.





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.




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




Undeveloped acreage




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.


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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 subsidiary;





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





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





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





·
“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” 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; and





·
“Denbury Acquisition” refers to the Fund’s acquisition of approximately $893 million of oil and natural gas properties, which we refer to as the “Denbury Assets,” from Denbury Resources Inc. in May 2010.


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FORWARD–LOOKING STATEMENTS




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





·
business strategies;





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





·
drilling locations;





·
oil and natural gas reserves;





·
technology;





·
realized oil and natural gas prices;





·
production volumes;





·
lease operating expenses;





·
general and administrative expenses;





·
future operating results; and





·
plans, objectives, expectations and intentions.





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





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





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





·
uncertainty inherent in estimating our reserves;





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





·
cash flows and liquidity;





·
potential shortages of drilling and production equipment;





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




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·
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;





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





·
the material weakness in our internal control over financial reporting;





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





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





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





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PART I





ITEM 1.     BUSINESS





Overview




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





We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties and our business activities are conducted through OLLC, our wholly owned subsidiary. All of our assets were received from the Fund in connection with our initial public offering (“IPO”) on December 22, 2010 and include oil and gas producing properties located in Alabama, Arkansas, Kansas, Louisiana, New Mexico, Oklahoma and Texas and an overriding royalty interest in Florida. These properties consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, predictable production profiles. As of December 31, 2010, our total estimated proved reserves were approximately 30.4 MMBoe, of which approximately 68% were oil and NGLs and 68% were classified as proved developed reserves. As of December 31, 2010, our estimated proved reserves had a standardized measure of $498.4 million. As of December 31, 2010, we produced from 2,140 gross (539 net) producing wells across our properties, with an average working interest of 25%, and a 68% value-weighted average working interest, which is calculated by dividing (a) the aggregate sum of the products of each property’s working interest and standardized measure as of December 31, 2010 by (b) the aggregate standardized measure for all properties, as of December 31, 2010.





Oil and natural gas reserve information included in this Form 10-K is derived from our reserve report prepared by Miller and Lents, Ltd., our independent reserve engineers. The following table summarizes information about our proved oil and natural gas reserves by geographic region as of December 31, 2010 and our average net production for the period of December 22 to December 31, 2010:




Estimated Net Proved ReservesOil &





Natural





Standardized (1)


Average


ProducingCond.


NGLs


Gas





Measure


Net Production


Wells(MBbls)


(MBbls)


(MMcf)


MBoe


($ millions)


Boe/d


% of total


% liquids


Gross


NetPermian Basin


16,649.0



142.1



9,786.8



18,422.2


$
325.1



2,203



41
%

77
%


1,737



331Ark-La-Tex


1,116.4



1,052.3



32,745.4



7,626.3



94.1



1,749



33
%

34
%


199



118Mid-Continent


929.5



0.1



10,767.2



2,724.1



33.7



803



15
%

33
%


192



86Gulf Coast


790.0



164.1



4,259.5



1,664.0



45.5



597



11
%

74
%


12



4Total


19,484.9



1,358.6



57,558.9



30,436.6


$
498.4



5,352



100
%

56
%


2,140



539


(1)
As of December 31, 2010 our standardized measure of discounted future net cash flows was $498.4 million. Standardized measure is calculated in accordance with GAAP.  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.


Developments in 2010 and 2011





Initial Public Offering of QR Energy, LP





On December 22, 2010, we completed our IPO of 15,000,000 common units representing limited partner interests in the Partnership at $20.00 per common unit for total net proceeds of $279.8 million. Our common units are traded on the New York Stock Exchange (“NYSE”) under the symbol “QRE.” In connection with the IPO, the Fund contributed to us certain fields in the Permian Basin and the Ark-La-Tex, Mid-Continent and Gulf Coast areas and an overriding royalty interest in the Gulf Coast area in exchange for 11,297,737 common units and 7,145,866 subordinated units. In exchange, we used the net proceeds from the IPO, together with borrowings of $225 million under the Credit Agreement, described below, to make a cash distribution to the Fund of $300 million and to repay in full $200 million of the Fund’s debt assumed at the closing of the IPO.




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On January 3, 2011, the underwriters exercised in full their over-allotment option to purchase an additional 2,250,000 common units issued by the Partnership at the initial public offering price. Total net proceeds from the exercise of the underwriters’ over-allotment option, after deducting estimated offering costs, were  $42 million and were paid to the Predecessor. Upon completion of the IPO and the underwriters' exercise of their over-allotment option, we had 28,547,737 common units, 7,145,866 subordinated units and 35,729 general partner units outstanding. Following our IPO and the underwriters’ exercise of their over-allotment option, the Fund owned approximately 39.6% of the common units and 100% of the subordinated units. The Fund is also entitled to a management incentive fee provided we meet certain distribution levels during any given quarter.The management incentive fee and general partner units are owned by our general partner. For a detailed description of the management incentive fee, see “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.”





New Credit Agreement





On December 22, 2010, in connection with the IPO, we entered into a Credit Agreement between us, our general partner, OLLC as borrower and a syndication of banks as lenders (the “Credit Agreement”). The Credit Agreement is a five-year, $750 million revolving credit facility with a borrowing base of $300 million. The borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, NGL and oil reserves, which will take into account the prevailing natural gas, NGL and oil prices and associated differentials at such time which is then adjusted for the impact of our commodity derivative contracts.




Predecessor Acquisition of Denbury Resources Properties





Quantum Resources Management, a wholly owned subsidiary of the Predecessor, entered into a purchase and sale agreement effective May 1, 2010 to acquire certain oil and natural gas properties from Denbury Resources, Inc. for $893 million. Total proved reserves of the acquired properties were estimated by our internal reserve engineers to be 77 MMBoe as of May 14, 2010. The Denbury properties comprised approximately 60% of the total properties conveyed to us on December 22, 2010 by the Fund.


Business Strategy





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





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





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





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





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





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





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




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Competitive Strengths





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





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





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





·
Our relationship with Quantum Resources Management, which provides us with extensive technical expertise in and familiarity with our core focus areas;





·
Our relationship with Quantum Energy Partners, which will help us in the evaluation and execution of future acquisitions;





·
Our substantial operational control of our assets, which will allow us to manage our operating costs and better control capital expenditures, as well as the timing of development activities;





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





·
Our significant inventory of identified low-risk, oil-weighted development projects in our core operating regions, which we believe will provide us with the ability to grow our production through 2015, based on production estimates in our reserve report dated December 31, 2010; and





·
Our competitive cost of capital and financial flexibility.





Our Relationship with the Fund





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




As of December 31, 2010, the Fund had total estimated proved reserves of 59.8 MMBoe, of which approximately 73% were proved developed reserves, with standardized measure of $721.0 million, and interests in more than 1,000 gross (630 net) oil and natural gas wells. The Fund had average net production of approximately 13,839 Boe/d for the period from January 1, 2010 through December 21, 2010. The estimates of proved reserves owned by the Fund as of December 31, 2010 are based on a reserve report prepared by Miller and Lents, Ltd., the Fund’s independent reserve engineers. The Fund’s assets include legacy properties with characteristics similar to our properties, and we believe that the majority of these assets are currently suitable for acquisition by us, based on our criteria that properties consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, low-decline, predictable production profiles. The Fund has informed us that it intends to offer us the opportunity to purchase its mature onshore producing oil and natural gas assets, from time to time, in future periods at mutually agreeable prices.





The Fund is contractually committed to providing us with opportunities to purchase additional proved reserves in future periods under specified circumstances. Under the terms of our omnibus agreement, the Fund has committed to offer us the first opportunity to purchase properties that it may offer for sale, so long as the properties consist of at least 70% proved developed producing reserves, as measured by value. Approximately 70% of the Fund’s estimated reserves are classified as proved developed producing, based on the Fund’s December 31, 2010 third-party reserve report. Additionally, we believe the percentage of the Fund’s estimated reserves classified as proved developed producing will increase over time as the Fund invests its capital to convert its undeveloped properties to proved developed producing. It is difficult to predict which properties the Fund may offer for sale in future periods or the reserve classifications of any such properties. As a result, we are unable to quantify the number of potential sale transactions that may meet the 70% proved developed producing reserve criteria.




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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.





Additionally, the Fund will agree to allow us to participate in its acquisition opportunities to the extent that it invests any of the remaining approximately $150 million of its unfunded committed equity capital. Specifically, the Fund will agree to offer us the first option to acquire at least 25% of each acquisition available to it, so long as at least 70% of the allocated value, as determined by the Fund acting in good faith under the omnibus agreement, is attributable to proved developed producing reserves. In addition to opportunities to purchase proved reserves from, and to participate in future acquisition opportunities with the Fund, the general partner of the Fund will agree that if it or its affiliates establish another fund similar to the Fund, with the purpose of acquiring oil and natural gas properties, by December 22, 2012, it will cause such fund to provide us with a similar right to participate in such fund’s acquisition opportunities. These contractual obligations will remain in effect through December 22, 2015.




We believe that the Fund has a vested interest in our ability to increase our reserves and production since it holds an aggregate of approximately 39.6 % of our common units and all of our subordinated as of April 15, 2011. 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.





Our Relationship with 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 contribute or sell oil and natural gas assets to us in transactions that would be beneficial to all parties. Given this potential alignment of interests and the overlapping ownership of the management and general partners of Quantum Energy Partners, the Fund and us, we believe we will benefit from the collective expertise of the employees of Quantum Energy Partners, their extensive network of industry relationships and the access to potential acquisition opportunities that would not otherwise be available to us.




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Our Areas of Operation





On December 22, 2010, Quantum Resource Funds contributed to us certain fields in the Permian Basin and the Ark-La-Tex, Mid-Continent and Gulf Coast areas and an overriding royalty interest in the Gulf Coast area. The following discussion reflects activity from December 22, 2010 through December 31, 2010 and as of the period then ended.





Permian Basin





The Permian Basin area includes properties located in west Texas and southeast New Mexico and produce 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. The area produced 2,203 Boe/d, of which 77% were liquids, and accounted for 41% of our average daily net production for the period of December 22, 2010 through December 31, 2010.We operate properties representing approximately 82% of our estimated net total proved reserves for the area. Our net proved reserves as of December 31, 2010 were 18,422 MBoe, 91% of which were liquids.  Approximately 54% of our Permian Basin reserves were classified as proved developed and represented approximately 61% of our total proved reserve volumes as of December 31, 2010.  During 2011, we expect to invest approximately 76% of our total capital budget in the Permian Basin, primarily on infill drilling and well work in preparation for waterflood expansion.





The Fuhrman Field constituted approximately 39% of our estimated proved reserves as of December 31, 2010. Our Predecessor’s production from the Fuhrman Field was 303 MBoe, 347 MBoe and 342 MBoe for the years ended December 31, 2010, 2009 and 2008. The 2010 production comprised 284 MBbls of oil and 113 MMcf of natural gas. The 2009 production comprised 325 MBbls of oil and 133 MMcf of natural gas. The 2008 production comprised 320 MBbls of oil and 134 MMcf of natural gas.





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 and Smackover Carbonate at depths ranging from 6,500 to 11,000 feet. The area produced 1,749 Boe/d, of which 34% were liquids, and accounted for 33% of our average daily net production for the period of December 22, 2010 to December 31, 2010.We operate properties representing approximately 97% of our estimated net total proved reserves for the area.  During 2010, we did not drill any wells in the Ark-La-Tex area. Our net proved reserves as of December 31, 2010 were 7,626 MBoe, 28% of which were liquids.  Approximately 85% of our Ark-La-Tex reserves were classified as proved developed and represented approximately 25% of our total proved reserves as of December 31, 2010.  During 2011, we expect to invest approximately 19% of our total capital budget in the Ark-La-Tex area, primarily on recompletions and artificial lift implementation.





Mid-Continent





The Mid-Continent area includes properties located in Oklahoma and southwestern Kansas.  These properties produce from formations such as the Cottage Grove Sand, Atoka, Redfork and Lansing at depths ranging from 6,000 to 15,000 feet. We operate properties representing approximately 62% of our estimated net total proved reserves for the area.  During 2010, we did not drill any new wells in the Mid-Continent area.  Our net proved reserves as of December 31, 2010 were 2,724 MBoe, 34% of which were liquids. The Mid-Continent area’s reserves were classified as 100% proved developed and represented 9% of our total proved reserves as of December 31, 2010. The area produced 803 Boe/d, of which 33% were liquids, and accounted for 15% of our average daily net production for the period from December 22, 2010 through December 31, 2010.During 2011, we expect to invest approximately 4% of our total capital budget in the Mid-Continent area, primarily on recompletions and workovers.


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Gulf Coast




The Gulf Coast area includes properties located in southern Alabama and southeast Texas. We also own an 8.05% overriding royalty interest (“ORRI”) on the Fund's oil production from the Jay Field located in the Florida panhandle. These properties produce from formations such as the Yegua Sand and Smackover Carbonate at depths ranging from 8,000 to 15,000 feet.  We operate properties representing approximately 59% of our estimated net total proved reserves for the area.  During 2010, we did not drill any new wells in the Gulf Coast area.  Our net proved reserves as of December 31, 2010 were 1,664 MBoe, 57% of which were liquids.  The Gulf Coast area’s reserves were classified as 100% proved developed and represented approximately 5% of our total proved reserves as of December 31, 2010. The area produced 597 Boe/d, of which 74% were liquids, and accounted for 11% of our average daily net production for the period of December 22, 2010 through December 31, 2010. During 2011, we expect to invest approximately 1% of our total capital budget in the Gulf Coast area, primarily on recompletions and workovers.





Our Oil and Natural Gas Data





Our Reserves




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





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





Qualifications of Responsible Technical Persons





Internal Quantum Resources Management Person.Our Senior Reservoir Engineer is the technical person primarily responsible for overseeing the preparation of our reserves estimates and is also responsible for liaison with and oversight of our third-party reserve engineer. The Senior Reservoir Engineer has more than 37 years of industry experience with positions of increasing responsibility in engineering and evaluations with Texaco, DeGolyer and McNaughton and Anadarko Petroleum Corporation. The Senior Reservoir Engineer holds a Bachelor of Science in Petroleum Engineering, a Master of Science in Engineering and is a registered professional engineer in Alabama, Louisiana, Mississippi and Texas.





Miller & Lents.  Miller & Lents, Ltd. is an independent oil and natural gas consulting firm. No director, officer, or key employee of Miller & Lents, Ltd. has any financial ownership in Quantum Resources Management, the Fund or any of their respective affiliates. Miller & Lents, Ltd.’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and Miller & Lents, Ltd. has not performed other work for Quantum Resources Management, the Fund or us that would affect its objectivity. The engineering audit presented in the Miller & Lents, Ltd. Report was over seen 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 from Ohio State University and is a registered professional engineer in Texas.


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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, 2010 based on reserve reports prepared by Miller & Lents, Ltd., our independent reserve engineers. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.





Oil &





Natural





StandardizedCond.


NGLs


Gas





Measure(MBbls)


(MBbls)


(MMcf)


MBoe


($ millions)Proved reserves:Developed


11,577.9



1,304.9



47,559.3



20,809.3


$
331.0Undeveloped


7,907.0



53.7



9,999.6



9,627.3



167.4Total


19,484.9



1,358.6



57,558.9



30,436.6


$
498.4


The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, see “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 Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.





Production, Revenue and Price History





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





Development of Proved Undeveloped Reserves





None of our proved undeveloped reserves as of December 31, 2010 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, our Predecessor’s drilling and development programs were substantially funded from its cash flow from operations. Our expectation is to continue to fund our drilling and development programs primarily from our cash flow from operations. Based on our current expectations of our cash flows and drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations and our expansions, extensions and processing of our waterfloods in the next five years from our cash flow from operations and, if needed, our credit facility. For a more detailed discussion of our liquidity position, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”




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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, 2010.




Oil


Natural GasGross


Net


Gross


NetOperated


407



357



161



129Non-operated


1,399



26



173



27Total


1,806



383



334



156


Developed Acreage





Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2010, all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2010 relating to our leasehold acreage.




DevelopedAcreageGross


NetPermian Basin


29,514



22,880Ark-La-Tex


31,535



17,916Mid-Continent


33,622



17,105Gulf Coast


2,575



1,566Total


97,246



59,467





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 report.


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Drilling Activities





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




Year Ended December 31,2010(1)


2009


2008Gross


Net


Gross


Net


Gross


NetProductive


72



4



123



3



77



12Dry


-



-



-



-



2



2Total


72



4



123



3



79



14


(1)
We have not made an allocation of drilling activity for the 10-day period from December 22, 2010 through December 31, 2010 between us and the Predecessor, as the drilling activity for this period allocable to us is inconsequential given our portion consists of 3 gross and less than 1 net well.





Delivery Commitments





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.





Operations





General





We operated approximately 83% of our assets as determined by value, based on standardized measure as of December 31, 2010. We design and manage the development, recompletion or workover for all of the wells we operate and supervise operation and maintenance activities. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on the properties we operate. Independent contractors provide all the equipment and personnel associated with these activities. Pursuant to our general partner’s services agreement, Quantum Resources Management provides certain administrative services to us. Quantum Resources Management employs production and reservoir engineers, geologists and other specialists, as well as field personnel. See “Item 13. Certain Relationships and Related Transactions, and Director Independence — Services Agreement” We charge the nonoperating partners a contractual administrative overhead charge for operating the wells. Some of our non-operated wells are managed by third-party operators who are typically independent oil and natural gas companies.





Administrative Services Fee





Our general partner has entered into a services agreement with Quantum Resources Management, pursuant to Quantum Resources Management will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee, through December 31, 2012. The administrative services fee for the period December 22, 2010 through December 31, 2010 was $0.1 million. After December 31, 2012, in lieu of the quarterly administrative services fee, our general partner will reimburse Quantum Resources Management, on a quarterly basis, for the allocable expenses it incurs in its performance under the services agreement, and we will reimburse our general partner for such payments it makes to Quantum Resources Management. Quantum Resources Management will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. For a detailed description of the administrative services fee paid Quantum Resources Management pursuant to the services agreement, see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Services Agreement”.




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Oil and Natural Gas Leases





The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on our properties range from less than 1% to 36%, resulting in a net revenue interest to us ranging from 64% to 100%, or 85% on average. As of December 31, 2010, all of our leases are held by production.





Marketing and Major Customers





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




Partnership





Predecessor2010(1)


2010(1)


2009


2008ConocoPhillips


23
%



(2)



(2)



(2)Plains Marketing LP


16
%



(2)


10
%



(2)Shell Trading US Company


10
%


45
%


24
%


51
%Sunoco Inc R&M



(2)


10
%


12
%



(2)




(1)
In 2010, we evaluated concentration of credit risk for us and the Predecessor by analyzing customer receipts from the oil and gas assets as if the Predecessor transferred title of the properties to us on January 1, 2010.





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





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





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





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. All of our current commodity derivative contracts are fixed price swaps with NYMEX 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 Agreement) 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. Each of the counterparties to our derivative contracts is a lender in our Credit Agreement. We will continue to evaluate the benefit of employing derivatives in the future. See “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.




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Seasonal Nature of Business





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





Environmental Matters and Regulation





General





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





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





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





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





Hazardous Substances and Waste





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




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





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





Water Discharges





The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by 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 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 Oil Pollution Act of 1990, as amended, or OPA, amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.





It is customary to recover hydrocarbons from formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate natural gas production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial results of the study anticipated to be available by late 2012, and final result in 2014. In addition, for the second consecutive session, the federal Congress is considering two companion bills, known as the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act,” that would repeal an exemption in the federal Safe Drinking Water Act for the underground injection of hydraulic fracturing fluids other than diesel near drinking water sources. Moreover, some states have adopted, and other states, including Texas, are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. On March 1, 2011, a bill was introduced in the Texas Senate that, if adopted, would require written disclosure to the Railroad Commission of Texas, or “RCT,” of specific information about the fluids, proppants and additives used in hydraulic fracturing treatment operations and, on March 11, 2011, a bill was introduced in the Texas House of Representatives that would require service companies to submit “master lists” of base fluids, additives and chemical constituents to be used in hydraulic fracturing activities in Texas, subject to certain trade secret protections, to the RCT.If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could increase our costs of compliance, impose operational delays and make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced. In addition, if hydraulic fracturing is regulated at the federal level, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements and attendant permitting delays and potential increases in costs. Some or all of these developments could have a material adverse effect on our business, financial condition and results of operations.





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Air Emissions





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





Climate Change





In December 2009, the EPA published its findings that emissions of carbon dioxide, or CO2, methane and other greenhouse gases, or GHGs, present an endangerment to public 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 climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act that require reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain large stationary sources, effective January 2, 2011. The EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or PSD, and Title V permitting programs. This rule tailors these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources being the first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions will also be required to reduce those emissions according to “best available control technology” standards for GHG.  Moreover, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011.





In addition, the U.S. Congress has, from time to time, considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce.





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





National Environmental Policy Act





Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or NEPA. NEPA requires federal agencies, including the 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 the development of oil and natural gas projects.




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Endangered Species Act





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





OSHA





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





Other Regulation of the Oil and Natural Gas Industry





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





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





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;




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·
the plugging and abandoning of wells; and





·
notice to surface owners and other third parties.





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





Natural Gas Regulation





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





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





State Regulation





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





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





Employees




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




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As of December 31, 2010, Quantum Resources Management had 211 employees, including 20 engineers, 3 geologists and 7 land professionals. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that Quantum Resources Management’s relations with its employees are satisfactory. We will also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed.





Offices





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 atwww.qrenergylp.comas 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 atwww.sec.govor 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 and the charters of our audit committee and conflicts committee. No information from either the SEC’s website or our website is incorporated herein by reference.




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ITEM 1A. RISK FACTORS





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





Risks Related to Our Business





We may not have sufficient cash to pay the minimum quarterly distribution on our common units, following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner.





We may not have sufficient available cash each quarter to pay the minimum quarterly distribution of $0.4125 per unit or any other amount.





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





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





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





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





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





·
the effectiveness of our commodity price hedging strategy;





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





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





·
the cost of acquisitions;





·
our ability to borrow funds under our credit facility;





·
prevailing economic conditions;





·
sources of cash used to fund acquisitions;





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





·
interest payments;





·
fluctuations in our working capital needs;




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·
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 minimum quarterly distribution that we expect to distribute. For a description of additional restrictions and factors that may affect our ability to make cash distributions to our unitholders, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”





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, 2010 reserve report, the average decline rate for our existing proved developed producing reserves is approximately 10% for 2011, 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 $12.5 million will enable us to maintain the current level of production from our assets through December 31, 2015. We may use the reserved cash to reduce indebtedness until we make the capital expenditures. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we may be unable to pay distributions at the minimum quarterly distribution 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 new our credit facility and the issuance of debt and equity securities.





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





·
our estimated proved oil and natural gas reserves;





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





·
the prices at which we sell our production;




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





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





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





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





The use of cash generated from operations to fund growth capital expenditures will reduce cash available for distribution to our unitholders. If the borrowing base under our credit facility or our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in estimated reserves or production or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed to fund our growth capital expenditures, our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.





Our failure to obtain the funds for necessary future growth capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions to our unitholders. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution, thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could adversely affect our ability to pay distributions to our unitholders at the then-current distribution rate or at all.





Oil and natural gas prices are very volatile. A decline in oil or natural gas prices will cause a decline in our cash flow from operations, which could cause us to reduce our distributions or cease paying distributions altogether.





The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:





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





·
weather conditions and the occurrence of natural disasters;





·
overall domestic and global economic conditions;





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





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





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





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





·
technological advances affecting energy supply and energy consumption;





·
domestic and foreign governmental regulations and taxation;





·
the impact of energy conservation efforts;




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·
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 2010, the NYMEX–WTI oil price ranged from a high of $91.51 per Bbl to a low of $68.01 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $6.01 per MMBtu to a low of $3.29 per MMBtu. For the five years ended December 31, 2010, the NYMEX–WTI oil price ranged from a high of $145.29 per Bbl to a low of $33.87 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $13.58 per MMBtu to a low of $2.51 per MMBtu.





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





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





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





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





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





·
impair our ability to pay distributions to our unitholders.





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





An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could significantly reduce our cash available for distribution and adversely affect our financial condition.





The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price we receive could significantly reduce our cash available for distribution to our unitholders and adversely affect our financial condition. We do not have or plan to have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials, which could adversely affect our results of operations.





Future price declines may result in a write-down of the carrying values of our oil and natural gas properties, which could adversely affect our results of operations.





We may be required under full cost accounting rules to write down the carrying value of our oil and natural gas properties if oil and natural gas prices decline or if we have substantial downward adjustments to our estimated proved reserves, capital expenditures that do not generate equivalent or greater value in estimated proved reserves, increases in our estimated future operating, development or abandonment costs or deterioration in our exploitation results.




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We utilize the full cost method of accounting for oil and natural gas exploration and development activities. Under this method, all costs associated with property exploration and development (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and direct overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities are capitalized. Under full cost accounting, we are required by SEC regulations to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of our oil and natural gas properties that is equal to the expected present value (discounted at 10%) of the future net cash flows from estimated proved reserves, including the effect of cash flow hedges, if applicable, calculated using the applicable price calculation for the period tested, as adjusted for “basis” or location differentials, or net wellhead prices held constant over the life of the reserves. Under current rules, which became effective for ceiling tests in 2009, the ceiling limitation calculation uses the SEC methodology to calculate the present value of future net cash flows from estimated proved reserves. For prior periods, the ceiling limitation calculation used oil and natural gas prices in effect as of the balance sheet date, as adjusted for basis or location differentials as of the balance sheet date, and held constant over the life of the reserves. If the net book value of our oil and natural gas properties exceeds our ceiling limitation, SEC regulations require us to impair or “write down” the book value of our oil and natural gas properties.





A ceiling test write-down would not impact cash flow from operating activities, but it would reduce partners’ equity on our balance sheet. The risk of a required ceiling test write-down of the book value of oil and natural gas properties increases when oil and natural gas prices are low. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred.





Our hedging strategy may be ineffective in removing the impact of commodity price volatility from our cash flows, which could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.





To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, 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. For 2011, approximately 28% of our estimated total oil and natural gas production, based on our reserve report dated December 31, 2010, is not currently covered by commodity derivative contracts. In addition, none of our estimated total NGL production is covered by commodity derivative contracts. Likewise, we do not have or plan to have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials, which could adversely affect our results of operations. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosure About Market Risk.”





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




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





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





Our hedging transactions expose us to counterparty credit risk.





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





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





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





·
the level of oil and natural gas prices;





·
future production levels;





·
capital expenditures;





·
operating and development costs;





·
the effects of regulation;





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





·      the availability of funds.





If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our estimated proved reserves could change significantly. For example, if the prices used in our December 31, 2010 reserve report had been $10.00 less per barrel for oil and $1.00 less per Mcf for natural gas, then the standardized measure of our estimated proved reserves as of that date would have decreased by $109.8 million, from $498.4 million to $388.6 million.




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Our standardized measure is calculated using unhedged oil, natural gas and NGL prices and is determined in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.





The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.





The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves.





The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect as of the date of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:





·
the actual prices we receive for oil, natural gas and NGLs;





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





·
the amount and timing of actual production;





·
the amount and timing of our capital expenditures;





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





·
changes in governmental regulations or taxation.





The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with Generally Accepted Accounting Principles, 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 2010 production and 60% of our estimated proved reserves as of December 31, 2010 relied on secondary and tertiary recovery techniques, which include waterfloods and injecting gases into producing formations to enhance hydrocarbon recovery. If production response to these techniques is less than forecasted for a particular project, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing the capital to employ these techniques. Risks associated with secondary and tertiary recovery techniques include the following:





·
lower-than-expected production;





·
longer response times;





·
higher-than-expected operating and capital costs;





·
shortages of equipment; and




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·
lack of technical expertise.





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





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





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





·
high costs, shortages or delivery delays of rigs, equipment, labor or other services;





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





·
unexpected operational events and conditions;





·
reductions in oil and natural gas prices;





·
increases in severance taxes;





·
adverse weather conditions and natural disasters;





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





·
title problems;





·
pipe or cement failures and casing collapses;





·
compliance with environmental and other governmental requirements;





·
environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;





·
lost or damaged oilfield development and service tools;





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





·
loss of drilling fluid circulation;





·
fires, blowouts, surface craterings and explosions;





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





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





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




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





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





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





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





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





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





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





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





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





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





·
outbid by competitors.





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




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





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





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





·
an inability to successfully integrate the businesses we acquire;





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





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





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





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





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





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





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





·
customer or key employee losses at the acquired businesses.





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





Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition, given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.





If our acquisitions do not generate the expected increases in available cash per unit, our ability to make distributions to our unitholders could be reduced.





We may experience a financial loss if Quantum Resources Management is unable to sell a significant portion of our oil and natural gas production.





Under our services agreement, Quantum Resources Management 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.




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In addition, a failure by any of these companies, or any purchasers of our production, to perform their payment obligations to us could have a material adverse effect on our results of operation. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge in the earnings of that period for the probable loss and could suffer a material reduction in our liquidity and ability to make distributions to our unitholders.





We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.





The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Many of our competitors are large independent oil and natural gas companies that possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Any inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.





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





We may be unable to pay the minimum quarterly distribution or the then-current distribution rate without borrowing under our 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  $225 million of debt outstanding as of December 31, 2010. 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:




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





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





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





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





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





Our credit facility has 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 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 “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 fail to provide audited financial statements within 105 days after the end of our fiscal year end and reviewed financial statements within 45 days after the end of our interim periods, we will be in violation of our covenants. If we violate any provisions of our credit facility that are not cured or waived within the appropriate time periods provided in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.








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. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, NGL and oil reserves, which will take into account the prevailing natural gas, NGL and oil prices at such time, as adjusted for the impact of our commodity derivative contracts. In the future, we may be unable to access sufficient capital under our credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.





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




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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 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, 2010,  5.3 MMBoe of our estimated proved reserves and 1.6 MMBoe of our estimated proved undeveloped reserves, or  18% of our estimated proved reserves and 16% 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;




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·
the operators’ expertise and financial resources;





·
the approval of other participants in such properties; and





·
the selection and application of suitable technology.





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





Our historical financial information may not be representative of our future performance.





The historical financial information included in this report is derived from our historical financial statements for periods prior to our initial public offering. Our audited historical financial statements were prepared in accordance with GAAP. Accordingly, our historical financial information does not reflect what our results of operations and financial condition would have been had we been a public entity during the periods presented, or what our results of operations and financial condition will be in the future.





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 “Item 1. Business — Environmental Matters and Regulation” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.





Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.





In December 2009, the U.S. Environmental Protection Agency, or EPA, published its findings that emissions of carbon dioxide, or CO2, methane and other greenhouse gases, or GHGs, present an endangerment to public 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 climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the existing Clean Air Act that require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary large sources, effective January 2, 2011.  The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or PSD, and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.  Facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG.  Moreover, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011.




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In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.  See “Item 1. Business — Environmental Matters and Regulation.”





Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.





Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations.





There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to our operations and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our business, financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance. See “Item 1. Business — Environmental Matters and Regulation” for more information.




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The third parties on whom we rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business.





The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. See “Item 1. Business — Environmental Matters and Regulation” 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 recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.





The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents.  Certain bona fide hedging transactions or positions would be exempt from these position limits.  It is not possible at this time to predict whether or when the CFTC will finalize these regulations or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make distributions. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.





Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.





Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion of certain oil and natural gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production. This process is typically regulated by state oil and natural gas agencies. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time,the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, with initial results of the study anticipated to be available by late 2012, and final result in 2014. In addition, for the second consecutive session, the federal Congress is considering two companion bills, known as the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act,” that would repeal an exemption in the federal Safe Drinking Water Act for the underground injection of hydraulic fracturing fluids other than diesel near drinking water sources. Moreover, some states have adopted, and other states, including Texas, are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. On March 1, 2011, a bill was introduced in the Texas Senate that, if adopted, would require written disclosure to the Railroad Commission of Texas, or “RCT,” of specific information about the fluids, proppants and additives used in hydraulic fracturing treatment operations and, on March 11, 2011, a bill was introduced in the Texas House of Representatives that would require service companies to submit “master lists” of base fluids, additives and chemical constituents to be used in hydraulic fracturing activities in Texas, subject to certain trade secret protections, to the RCT. Adoption of legislation or any implementing regulations placing restrictions on hydraulic fracturing activities could increase our costs of compliance with potentially applicable permitting, financial assurance, construction, monitoring, reporting and plugging and abandonment requirements, impose operational delays and make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced. In addition, if hydraulic fracturing is regulated at the federal level, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements and attendant permitting delays and potential increases in costs. Some or all of these developments could have a material adverse effect on our business, financial condition and results of operations.




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





Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and implied distribution yield. The distribution yield is often used by investors to compare and rank similar yield oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt.





Risks Inherent in an Investment in Us





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





Our general partner has control over all decisions related to our operations. As of April 15, 2011, the Fund owned a 51.6% limited partner interest in us, and our general partner is owned 50% by an entity controlled by Mr. Neugebauer and Mr. VanLoh, who are directors of our general partner and also managing partners of Quantum Energy Partners, and 50% by an entity controlled by Mr. Smith, our Chief Executive Officer, a director of our general partner and Chief Executive Officer and a director of Quantum Resources Management and Mr. Campbell, our President and Chief Operating Officer, a director of our general partner and President, Chief Operating Officer and a director of Quantum Resources Management. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, certain directors and officers of our general partner are directors or officers of affiliates of our general partner, including Quantum Resources Management and Quantum Energy Partners, and certain of our executive officers and directors will continue to have economic interests, investments and other economic incentives in funds affiliated with Quantum Energy Partners. Conflicts of interest may arise in the future between the Fund, Quantum Energy Partners and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. These potential conflicts include, among others, the following situations:





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




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





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





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





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





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





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





·
after December 31, 2012, our general partner will determine which costs, including allocated overhead, incurred by it and its affiliates, including Quantum Resources Management, are reimbursable by us. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us;





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





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





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





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





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





See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”




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





Our partnership agreement provides that the Fund and Quantum Energy Partners and their respective affiliates are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, except for the limited obligations of the Fund described below with respect to our omnibus agreement, the Fund and Quantum Energy Partners and their respective affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Under the terms of our omnibus agreement, the Fund is only obligated to offer us the first option to acquire 25% of each acquisition that becomes available to the Fund, so long as at least 70% of the allocated value (as determined in good faith by the Fund) is attributable to proved developed producing reserves. In addition, the terms of our omnibus agreement require the Fund to give us a preferential opportunity to bid on any oil or natural gas properties that the Fund intends to sell only if such properties are at least 70% proved developed producing reserves (as determined in good faith by the Fund). In addition to opportunities to purchase additional properties from, and to participate in future acquisition opportunities with, the Fund, the general partner of the Fund has agreed that, if it or its affiliates establish another fund to acquire oil and natural gas properties by December 31, 2012, it will cause such fund to provide us with a similar right to participate in such fund’s acquisition opportunities. These provisions of the omnibus agreement will expire 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, which factors may make it more difficult for us to compete with the Fund and Quantum Energy Partners with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”





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 available to our general partner Quantum Resources Management’s personnel in a manner that will allow us to carry on our business in the same manner in which it was carried on by our Predecessor.





Quantum Resources Management provides substantially similar services to the Fund, one of our affiliates. Should Quantum Energy Partners form other funds, Quantum Resources Management may enter into similar arrangements with those new funds. Because Quantum Resources Management 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. The assets that the Fund owns with respect to Quantum Resources Management that provides such services had net production of approximately 13,851 Boe/d for 2010. Additionally, Quantum Resources Management may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of the Fund or other funds. There is no requirement that Quantum Resources Management favor us over the Fund or other funds in providing its services. If the employees of Quantum Resources Management and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.


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We have material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.





Our Predecessor has been a private company with limited accounting personnel and other supervisory resources to adequately execute its accounting processes and address our internal control over financial reporting. This lack of adequate accounting resources contributed to audit adjustments to the financial statements for 2009 and 2010.  In connection with our Predecessor’s audit for the year ended December 31, 2009 and 2010, our Predecessor’s independent registered public accounting firm identified and communicated to our Predecessor and to us material weaknesses, including a material weakness related to maintaining an effective control environment in that the design and operation of its controls have not consistently resulted in effective review and supervision.  Certain of these material weaknesses, including the material weakness in the control environment, also exist at the Partnership level since the same processes and controls support the Partnership. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.




The lack of adequate staffing levels and communication throughout the organization  resulted in insufficient time spent on review and approval of certain information used to prepare our Predecessor’s and the Partnership's financial statements.  In addition, we did not design and operate effective controls over the month end closing process to allow for management's review on a timely, consistent and effective basis.  That combined with an IT environment that lacks segregation of duties, insufficient controls over change management processes for the related financial reporting systems, and a lack of integration of key systems all contributed to material weaknesses in the overall control environment. The lack of adequate staffing and insufficient supervision throughout the organization also resulted in the lack of design of proper policies and procedures over several control activities, as further described below, which represent individual material weaknesses at the control activity level. These material weaknesses contributed to multiple audit adjustments.  The following are the individual control activity level material weaknesses:
 
 ·
We did not design and operate effective controls to ensure the completeness and accuracy of the inputs with respect to the full cost ceiling impairment test and depreciation, depletion and amortization calculations, resulting in audit adjustments in 2009 and 2010.
 
 ·
We did not design and operate effective controls over the calculation and review of the nonperformance risk adjustment related to the valuation of derivative contracts, resulting in audit adjustments in 2009 and 2010.
 
 ·
We did not design and operate effective controls to ensure that gas imbalance liabilities were appropriately recorded, resulting in audit adjustments in 2010.
 
 ·
We did not design and operate effective controls over the management of suspended revenue and revenue clearing balances and outside owners’ interests accruals, resulting in audit adjustments in 2010.
 
 ·
We did not design and operate effective controls to ensure that inventory balances were complete and accurate and movements recorded in a timely basis, resulting in audit adjustments in 2010.
 
 ·
We did not design and operate effective controls over acquisitions to ensure all material assets, liabilities, revenues and expenses were identified and recorded, resulting in audit adjustments in 2010.
 
 ·
We did not design and operate effective controls to ensure that the accounting for the IPO transaction and the associated conveyance accounting had been correctly accounted for, resulting in audit adjustments in 2010
 
 ·
We did not design and operate effective controls to ensure that executive and management compensation arrangements had been identified and the related expenses appropriately recorded, resulting in audit adjustments in 2010, some of which were out-of-period adjustments.
 
 In response, we have begun the process of evaluating our internal control over financial reporting, although we are in the early phases of our review and will not complete our review until later in 2011. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weaknesses previously identified. Each of the material weaknesses described above could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim consolidated financial statements that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses described above or avoid potential future material weaknesses.




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The management incentive fee we will pay to our general partner may increase in situations where there is no corresponding increase in distributions to our common unitholders.





Under our partnership agreement, for each quarter for which we have paid cash distributions that equaled or exceeded the Target Distribution, our general partner will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of the management incentive fee base, which will be an amount equal to the sum of:





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





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





The maximum amount of the management incentive fee payable to our general partner in respect of any quarter is not dependent upon the amount of distributions to unitholders increasing beyond 115% of our minimum quarterly distribution. As a result, the management incentive fee may increase as the value of our oil and natural gas reserves and other assets increase even though distributions to unitholders may remain the same or even decrease. In addition, our general partner may have a conflict in deciding whether to reserve cash to invest in developing our oil and natural gas properties to increase the value of our assets (which would increase the management incentive fee) or deciding to make cash available for distributions to our unitholders.





If our general partner converts a portion of its management incentive fee in respect of a quarter into Class B units, it will be entitled to receive pro rata distributions on those Class B units when and if we pay distributions on our common units, even if the value of our properties declines and a lower management incentive fee is owed in future quarters.





From and after the end of the subordination period and subject to certain exceptions, our general partner will have the continuing right, at any time when it has received all or any portion of the quarterly management incentive fee for three consecutive calendar quarters and shall be entitled to receive all or a portion of the management incentive fee for a fourth consecutive quarter, to convert into Class B units up to 80% of the management incentive fee for the fourth quarter in lieu of receiving a cash payment for each portion of the management incentive fee. The Class B units will have the same rights, preferences and privileges of our common units and will be entitled to the same cash distributions per unit as our common units, except in liquidation where distributions are made in accordance with the respective capital accounts of the units and will be convertible into an equal number of common units at the election of the holder. As a result, if the value of our properties declines in periods subsequent to the conversion, our general partner may receive higher cash distributions with respect to Class B units than it otherwise would have received in respect of the management incentive fee it converted. The Class B units issued to our general partner upon conversion of the management incentive fee will not be subject to forfeiture should the value of our assets decline in subsequent periods.




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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, our general partner is owned 50% by an entity controlled by Mr. Smith, the Chief Executive Officer and a director of our general partner and Chief Executive Officer and a director of Quantum Resources Management and Mr. Campbell, the President and Chief Operating Officer and a director of our general partner and President, Chief Operating Officer and a director of Quantum Resources Management. Mr. Smith and Mr. Campbell manage the Fund, and the Fund is also in the business of acquiring oil and natural gas properties. In addition, our general partner is owned 50% by an entity controlled by Mr. Neugebauer and Mr. VanLoh, who are directors of our general partner and also managing partners of Quantum Energy Partners. 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 “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. Additionally, while the general partner of the Fund has agreed that, if it or its affiliates establish another fund to acquire oil and natural gas properties by December 22, 2012, it will cause such fund to provide us with a similar right to participate in such fund’s acquisition opportunities, the general partner of the Fund and its affiliates are under no obligation to create an additional fund, and even if an additional fund is created, our ability to consummate acquisitions in partnership with such fund will be subject to each of the risks outlined above. The contractual obligations under the omnibus agreement automatically terminate on December 22, 2015. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”




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After December 31, 2012, we will have to reimburse Quantum Resources Management for all allocable expenses it incurs on our behalf in its performance under the services agreement as opposed to paying the fixed services fee in effect until December 31, 2012. Our actual allocated expenses after December 31, 2012 may be substantially more than the administrative services fee we pay under the fixed rate currently in effect, which could materially reduce the cash available for distribution to our unitholders at that time.





Under the services agreement that our general partner has entered into, from December 22, 2010 through December 31, 2012, Quantum Resources Management will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. For 2010, 3.5% of our Adjusted EBITDA, calculated prior to the payment of the fee, was $0.1 million. After December 31, 2012, in lieu of the quarterly administrative services fee, our general partner will reimburse Quantum Resources Management, on a quarterly basis, for the allocable expenses it incurs in its performance under the services agreement, and we will reimburse our general partner for such payments it makes to Quantum Resources Management. Our actual allocated expenses after December 31, 2012 may be substantially more than the administrative services fee we pay under the fixed rate currently in effect, which could materially reduce the cash available for distribution to our unitholders at that time. For a detailed description of the administrative services fee, see “Item 13. Certain Relationships and Related Transactions, and Director Independence.”





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 unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. Affiliates of the Fund and Quantum Energy Partners, as the owners of our general partner, will have the power to appoint and remove our general partner’s directors.





Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner will be chosen by affiliates of the Fund and Quantum Energy Partners. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.




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Our general partner has control over all decisions related to our operations. Since affiliates of the Fund and Quantum Energy Partners own our general partner and, through ownership of the general partner of the Fund, own a 51.6% limited partner interest in us as of March 31, 2011, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by the Fund and its affiliates) after the subordination period has ended. Assuming we do not issue any additional common units and the Fund does not transfer its common units, the Fund will have the ability to amend our partnership agreement, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholder once the subordination period ends. Furthermore, the goals and objectives of the affiliates of the Fund and Quantum Energy Partners that hold our common units and our general partner relating to us may not be consistent with those of a majority of the other unitholders. See “— Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of our unitholders.”





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





Maintenance capital expenditures are those capital expenditures required to maintain our long-term asset base, including expenditures to replace our oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation. In addition, the ability of our general partner to receive a management incentive fee is based on the amount of cash distributed to our unitholders from operating surplus, which in turn is partially dependent upon its determination of our estimated maintenance capital expenditures. If estimated maintenance capital expenditures are lower than actual maintenance capital expenditures, then our general partner may be entitled to the management incentive fee at times when cash distributions to our unitholders would not have come from operating surplus if operating surplus was reduced by actual maintenance capital expenditures.





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





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





·
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;




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·
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.





Even if our unitholders are dissatisfied, they cannot remove our general partner without its consent.





The public unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2⁄3% of all outstanding units voting together as a single class is required to remove our general partner. As of March 31, 2011, affiliates of the Fund and Quantum Energy Partners own our general partner and, through ownership of the general partner of the Fund, own a 51.6% limited partner interest in us.





Our general partner’s interest in us, including its right to receive the management incentive fee, and the control of our general partner may be transferred to a third party without unitholder consent.





Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner, who are affiliates of both the Fund and Quantum Energy Partners, from transferring all or a portion of their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and officers. Additionally, our general partner or its owners may assign the right to receive the management incentive fee and to convert such management incentive fee into Class B units to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the holders. To the extent the owners of our general partner have interests aligned with those of our unitholders to grow our business and increase our distributions, any assignment of the right to receive the management incentive fee and to convert such management incentive fee into Class B units to a third party would diminish the incentives of the owners of our general partner to pursue a business strategy that favors us.





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





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




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





Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:





·
our unitholders’ proportionate ownership interest in us will decrease;





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





·
the ratio of taxable income to distributions may increase;





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





·
the market price of our common units may decline.





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





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





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





If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. As of April 15, 2011, the Fund owned a 51.6% limited partner interest in us including both common and subordinated units. Our subordinated units convert to common units on the earlier of two years from the date of the initial public offering or the date our general partner is removed without case.





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





Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes and any payments in respect of the management incentive fee, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in the glossary and generally would result from cash received from 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 our minimum quarterly distribution and a lower Target Distribution used in calculating the management incentive fee paid to our general partner, which may have the effect of increasing the likelihood that our general partner would earn the management incentive fee in future periods.




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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 federal income tax purposes. If the IRS were to treat us as a corporation, then our cash available for distribution to our unitholders would be substantially reduced.





The anticipated after-tax economic benefit of an investment in the units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.





Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based on our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.




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





If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.





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





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





The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.





Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution and the Target Distribution may be adjusted to reflect the impact of that law on us.





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





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.




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





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





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




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We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.





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





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





Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.





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





We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the Partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.





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.




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ITEM 1B. UNRESOLVED STAFF COMMENTS





None.





ITEM 2.    PROPERTIES





Information regarding our properties is contained in Item 1. Business “—Our Areas of Operation” and “—Our Oil and Natural Gas Data” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” contained herein.





ITEM 3.    LEGAL PROCEEDINGS





We are currently involved in one dispute or legal action arising in the ordinary course of business.  We do not believe the outcome of such dispute or legal action will have a material adverse effect on our consolidated financial statements, and no amounts have been accrued at December 31, 2010.





ITEM 4.    (REMOVED AND RESERVED)


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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 April 15, 2011, based upon information received from our transfer agent and brokers and nominees, we had 24 common unitholders of record. This number does not include owners for whom common units may be held in “street” names. The daily high and low sales prices per common unit for the period from December 17, 2010 (the initial listing date of the units) through December 31, 2010 was $21.50 to $19.53.





We have also issued 7,145,866 subordinated units, for which there is no established public trading market. The subordinated units are held by affiliates of the Fund.





Cash Distributions to Unitholders





On January 25, 2011, the board of directors of Quantum Resources Management declared a quarterly cash distribution for the fourth quarter of 2010 of $0.0448 per unit. The distribution represented a proration of our minimum quarterly distribution of $0.4125 per unit for the period from December 22, 2010 through December 31, 2010. The aggregate distribution of $1.6 million was paid on February 11, 2011 to unitholders of record as of the close of business on February 7, 2011.





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.





Cash Distribution Policy





Our partnership agreement requires that within 45 days after the end of each quarter, beginning with the quarter ended December 31, 2010, we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our general partner.





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





·
less the amount of cash reserves established by the General Partner to:





(i)
provide for the proper conduct of our business (including payments to our general partner for reimbursement of expenses it incurs on our behalf and payment of any portion of the management incentive fee to the extent it will become payable in connection with the payment of the distribution),





(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 our general partner for any one or more of the next four quarters.





·
plus, if our general partners so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter.





During Subordination Period.




Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter in the following manner during the subordination period:




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·
first, to the general partner 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 for the quarter;





·
second, to the general partner 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 the general partner in accordance with its percentage interest and to the unitholders holding subordinated units, pro rata, a percentage equal to 100% less the general partner’s percentage interest, until there has been distributed in respect of each subordinated unit then outstanding an amount equal to the minimum quarterly distribution for such quarter; and





·
thereafter, to the general partner and all unitholders, pro rata;





After Subordination Period.




Our partnership agreement requires that after the subordination period, we make distributions of available cash from operating surplus for any quarter to the general partner and all unitholders in accordance with their percentage interest, pro rata





Management Incentive Fee





For each quarter for which we have paid cash distributions that equaled or exceeded 115% of our minimum quarterly distribution (our “Target Distribution”), or $0.4744 per unit, our general partner will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of our management incentive fee base, which will be an amount equal to the sum of:





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





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





This management incentive fee base will be calculated as of December 31 (with respect to the first and second calendar quarters and based on a third-party fully engineered reserve report) or June 30 (with respect to the third and fourth calendar quarters and based on an internally engineered third-party reserve report, unless estimated proved reserves increased by more than 20% since the previous calculation date, in which case a third-party audit of our internal estimates will be performed) immediately preceding the quarter in respect of which payment of a management incentive fee is due.





In addition, at the end of the subordination period and subject to certain limitations, our general partner will have the continuing right to convert up to 80% of management incentive fee into Class B Units, which have the same rights, preferences and privileges as our common units, except in liquidation and will be convertible into common units at the holder’s election, thereby increasing our general partner’s ownership and economic interest in us. If our general partner exercises its right to convert a portion of the management incentive fee with respect to that quarter into Class B units, then the management incentive fee base described above will be reduced in proportion to the percentage of such fee converted. As a result, any conversion will reduce the amount of the management incentive fee for subsequent quarters, subject to potential increases in future quarters as a result of an increase in our management incentive fee base. Our general partner will, however, be entitled to receive distributions on the Class B units that it owns as a result of converting the management incentive fee, including in respect of the quarter for which such fee was converted. The reduction in the management incentive fee as a result of any conversion will directly offset the increase in distributions required by the newly issued Class B units. In addition, following a conversion, our general partner will be able to make subsequent conversions once certain conditions have been met.


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Securities Authorized for Issuance under Equity Compensation Plans





See “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, 2010.





Unregistered Sales of Equity Securities





None.




Issuer Purchases of Equity Securities





None.




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ITEM 6.    SELECTED FINANCIAL DATA





The selected consolidated financial data presented as of December 31, 2010 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 years ended December 31, 2009, 2008, 2007 and periods in 2006 are derived from the audited financial statements of our Predecessor. The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “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


Our Predecessor PropertiesThousands of Dollars
December 22 to December 31,

2010


January 1 to

December 21,

2010


Year Ended

December 31,

2009


Year Ended

December 31,

2008


Year Ended

December 31,

2007


April 1 to

December 31,

2006


January 1, to September 7, 2006Statement of Operations Data:Revenues:Oil, natural gas, NGL and sulfur sales
$
3,014


$
244,572


$
69,823


$
233,465


$
163,368


$
17,886


$
38,744Processing fees and other

-



8,814



2,978



47,605



7,949



-



-Total Revenues

3,014



253,386



72,801



281,070



171,317



17,886



38,744Operating costs and expenses:Lease operating

734



76,512



33,328



90,424



77,767



6,604



9,540Production taxes

192



17,657



7,587



14,566



12,954



1,553



2,737Transportation, processing and other

13



11,673



3,926



26,189



4,728



177



-Inventory adjustment

-



2,566



-



-



-



-



-Impairment of oil and gas properties (2)

-



-



28,338



451,440



-



-



-Depreciation, depletion and amortization

913



66,482



16,993



49,309



42,889



5,579



3,299Accretion of asset retirement obligations

25



3,674



3,585



3,004



2,751



119



200Management fees(3)

-



10,486



12,018



12,018



11,482



6,895



-General and administrative and other

280



32,041



19,279



14,703



20,652



6,338



906Bargain purchase gain

-



-



(1,200
)


-



-



-



-Total operating costs and expenses

2,157



221,091



123,854



661,653



173,223



27,265



16,682Income (loss) from operations

857



32,295



(51,053
)


(380,583
)


(1,906
)


(9,379
)


22,062Other income (expenses):Gain (loss) on commodity derivative contracts

(7,694
)


13,577



(63,120
)


134,655



(150,389
)


41,823



(29,328
)Gain on equity share issuance

-



4,064



-



-



-



-



-Interest expense, net

(304
)


(22,179
)


(3,716
)


(12,417
)


(16,381
)


(2,857
)


-Other income (expense)

-



4,264



2,657



(10,039
)


7



-



(207
)Total other income (expense)

(7,998
)


(274
)


(64,179
)


112,199



(166,763
)


38,966



(29,535
)Income (loss) before income taxes

(7,141
)


32,021



(115,232
)


(268,384
)


(168,669
)


29,587



(7,473
)Income tax benefit (expense), net

42



(108
)


(182
)


(149
)


(25
)


(42
)


-Net income (loss)
$
(7,099
)

$
31,913


$
(115,414
)

$
(268,533
)

$
(168,694
)

$
29,545



(7,473
)General partner's interest in net income
$
(7
)Limited partners' interest in net income
$
(7,092
)Net loss per limited partner unit (basic and diluted)
$
(0.21
)Weighted average number of limited partner unitsoutstanding (basic and diluted)

33,444Other Financial Data:Adjusted EBITDA
$
1,690


$
116,152


$
48,513


$
78,465


$
50,602


$
(159
)

$
(3,974
)Cash Flow Data:Net cash provided by (used in):Operating activities
$
(283
)

$
95,945


$
64,907


$
75,282


$
24,839


$
(1,460
)

$
(6,478
)Investing activities

-



(956,877
)


(55,458
)


(137,161
)


(72,953
)


(500,313
)


(1,690
)Financing activities

2,478



903,448



(13,328
)


30,240



89,890



512,671



8,168Balance Sheet Data:Working capital
$
3,074




(1)

$
(74
)

$
67,139


$
27,356


$
23,444



n/aTotal assets

472,018




(1)


226,770



304,937



655,689



583,577



n/aTotal debt

225,000




(1)


86,450



88,750



226,275



224,500



n/aNon-controlling interests

-




(1)


14,733



133,978



235,201



308,337



n/aPartners' capital

197,605




(1)


(1,421
)


5,957



5,103



11,262



n/a





(1)
These balance sheet amounts are not presented as they are not included in the Predecessor’s financial statements included in “Item 8. Financial Statements and Supplementary Data.”


(2)
Our Predecessor recorded full-cost ceiling test impairments associated with its oil and natural gas properties in both 2009 and 2008.


(3)
Represents fees paid by the Fund to its general partner for the provision of certain administrative and acquisition services.


(4)
The Predecessor commenced operations on April 1, 2006. As such, the Predecessor initial fiscal year comprised the period from April 1, 2006 through December 31, 2006.


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Non-GAAP Financial Measures





We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash from operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income:





·
Plus:




·
Interest expense, including realized and unrealized gains and losses on interest rate derivative contracts;




·
Depletion, depreciation and amortization;




·
Accretion of asset retirement obligations;




·
Unrealized losses on commodity derivative contracts;




·
Income tax expense;




·
Impairments; and




·
General and administrative expenses that are allocated to us in accordance with GAAP in excess of the administrative services fee paid by our general partner and reimbursed by us.




·
Less:




·
Income tax benefit;




·
Interest income; and




·
Unrealized gains on commodity derivative contracts.




We use Adjusted EBITDA to calculate the quarterly administrative services fee our general partner pays to Quantum Resources Management under the services agreement between our general partner and Quantum Resources Management. See “Item 1. Business — Operations — General — 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 actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.





Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.


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The following table presents our calculation of Adjusted EBITDA. The table below further presents a reconciliation of Adjusted EBITDA to cash flows from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.




Partnership


Predecessor


Our Predecessor PropertiesThousands of Dollars

December 22 to December 31, 2010


January 1 to December 21, 2010


Year Ended

December 31, 2009


Year Ended

December 31, 2008


Year Ended

December 31, 2007


April 1 to December 31, 2006


January 1 to September 7, 2006Reconciliation of consolidated net income (loss) to Adjusted EBITDA:Net income (loss)

$
(7,099
)

$
31,913


$
(115,414
)

$
(268,533
)

$
(168,694
)

$
29,545


$
(7,473
)Unrealized (gains) losses on commodity derivative contracts


7,405



(8,204
)


111,113



(169,321
)


157,250



(38,301
)


-Depletion, depreciation and amortization


913



66,482



16,993



49,309



42,889



5,579



3,299Accretion of asset retirement obligations


25



3,674



3,585



3,004



2,751



119



200Interest expense, net


304



22,179



3,716



12,417



16,381



2,857



-Income tax expense (benefit), net


(42
)


108



182



149



25



42



-Impairment expense


-



-



28,338



451,440



-



-



-General and administrative expense in excess of the administrative services fee


184



-



-



-



-



-



-Adjusted EBITDA

$
1,690


$
116,152


$
48,513


$
78,465


$
50,602


$
(159
)

$
(3,974
)Reconciliation of Net Cash from OperatingActivities to Adjusted EBITDA:Net cash provided by (used in) operating activities

$
(283
)

$
95,945


$
64,907


$
75,282


$
24,839


$
(1,460
)

$
(6,478
)(Increase) decrease in working capital


1,702



(1,651
)


(24,941
)


9,010



3,342



(1,598
)


2,504Amortization of equity awards


(20
)


(3,470
)


-



-



-



-



-Purchase of commodity derivative contracts


-



-



-



2,694



7,546



-



-Amortization of costs of commodity derivative contracts


-



-



(1,219
)


(7,981
)


-



-



-Interest expense (1)


290



16,892



6,038



9,929



14,843



2,857



-Income tax expense, current


1



108



182



149



25



42



-Unrealized (gains) losses on investment in marketable equity securities


-



-



5,640



(5,640
)


-



-



-Realized losses on investment in marketable equity securities


-



-



(5,246
)


(1,968
)


-



-



-Gain (Loss) on disposal of furniture, fixtures and equipment


-



482



(723
)


-



-



-



-Bargain purchase gain


-



-



1,200



-



-



-



-Equity earnings of Ute Energy, LLC


-



3,782



2,675



(3,010
)


7



-



-Gain on equity share issuance


-



4,064



-



-



-



-



-Adjusted EBITDA

$
1,690


$
116,152


$
48,513


$
78,465


$
50,602


$
(159
)

$
(3,974
)




(1)
Interest expense adjusted for noncash items comprising amortization of deferred financing costs and unrealized gains (losses) on interest rate derivative instruments.




61
 Table of Contents




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 “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 report. 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 report.


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 the Permian Basin (Texas and New Mexico) and the Ark-La-Tex (Arkansas, Louisiana and Texas), Mid-Continent (Oklahoma) and Gulf Coast (Florida and Alabama) areas. As of December 31, 2010, we had estimated net proved reserves of 19.5 MMBbl of oil and condensate, 57.6 Bcf of natural gas and 1.4 MMBbl of NGLs, or 30.4 MMBoe and a standardized measure of $498.4 million.




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 Table Of Contents




2010 Conveyance and Acquisitions





Partnership





On December 22, 2010, as part of our IPO, the Fund conveyed to us oil and natural gas producing properties located in Alabama, Arkansas, Kansas, Louisiana, New Mexico, Oklahoma, Texas and an 8.05% overriding oil royalty interest in Florida. As of December 31, 2010, these properties consisted of working interests in 2,140 gross (539 net) producing wells, of which we owned an approximate 25% average working interest.





Predecessor




On May 14, 2010, the Predecessor completed an acquisition of certain oil and natural gas properties with estimated total proved reserves of 77 MMBoe from Denbury Resources, Inc. for $893 million. The acquisition-related costs for the Denbury Acquisition were approximately $1.2 million and are recorded as operating expenses for 2010.





On January 28, 2009, the Predecessor completed an acquisition of 80 producing gas wells located in Arkansas and Louisiana with estimated total proved reserves of 4.2 MMBOE for approximately $48.7 million.





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;




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




·
Production expenses and general and administrative expenses; and




·
Adjusted EBITDA





Production Volumes




Production volumes directly impact our results of operations.  For more information about our 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 additional, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.




Oil prices. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality 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).




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 Table Of Contents




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




Natural Gas 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. In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2010, the NYMEX-WTI oil price ranged from a high of $91.51 per Bbl to a low of $68.01 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $6.01 per MMBtu to a low of $3.29 per MMBtu. For the five years ended December 31, 2010, the NYMEX-WTI oil price ranged from a high of $145.29 per Bbl to a low of $33.87 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $13.58 per MMBtu to a low of $2.51 per MMBtu.




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 estimated oil and natural gas production over a 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 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 have entered into an agreement with Quantum Resources Management with respect to all general and administrative costs and services it incurs on our general partner’s and our behalf.Under the services agreement, Quantum Resources Management is entitled to a quarterly administrative services fee in cash equal to 3.5% of the Adjusted EBITDA generated during the preceding quarter, calculated prior to the payment of the fee, in exchange for those services through December 31, 2012. Thereafter, our general partner will be required to reimburse Quantum Resources Management in full for the general and administrative expenses incurred or allocated to us by Quantum Resources Management in the performance of the services agreement. Our total general and administrative expenses include (i) the administrative services fee, (ii) our direct general and administrative costs, as well as (iii) an estimate of the relative portion of our indirect overhead costs incurred by the Fund that are in excess of the administrative services fee charged to us. We record the portion of total general and administrative expenses in excess of the administrative services fee as a capital contribution by the Fund and have therefore added back such portion in the calculation of Adjusted EBITDA. For a detailed description of the administrative services fee paid to Quantum Resources Management pursuant to the services agreement, please read “Item 13. Certain Relationships and Related Transactions, and Director Independence — Contracts with QRE GP, LLC and Its Affiliates — Services Agreement.”
 
 We typically evaluate our general and administrative expenses on a per Boe basis to monitor these costs and to benchmark against other producers.


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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. We also use Adjusted EBITDA to calculate the administrative services fee our general partner pays to Quantum Resources Management under the services agreement. For our definition of Adjusted EBITDA see “Item 6. Selected Financial Data – Non-GAAP Financial Measures.” For more information regarding the services agreement, see “Item 13. Certain Relationships and Related Transactions and Director Independence – Contracts with QRE GP, LLC 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 measure of another company because all companies may not calculate Adjusted EBITDA in the same manner. For further discussion, see “Item 6. Selected Financial Data – Non-GAAP Financials Measures.”





2011 Outlook





In 2011, our capital spending program is expected to be approximately $12.5 million excluding acquisitions. We anticipate spending approximately 76% in the Permian Basin primarily on infill drilling and well work in preparation for waterflood expansion and 19% in the Ark-La-Tex area primarily on recompletions and artificial lift implementation. Without considering potential acquisitions, we expect our aggregate production in 2011 to be approximately 1.9 MMBoe 2011, comprising 1.1 MMBbl of oil production, 0.7 MMBoe of natural gas production and 0.1 MMBbl of NGL production.





Commodity hedging remains an important part of our strategy to reduce cash flow volatility. For 2011, we have 2,238 Bbl/d of oil and 9,178 MMBtu/d of natural gas hedged at average prices of approximately $85.00 and $7.26. For 2012, we have 2,039 Bbl/d of oil and 8,192 MMBtu/d of natural gas hedged at average prices of approximately $85.25 and $6.45.  For 2013, we have 2,076 Bbl/d of oil and 7,474 MMBtu/d of natural gas hedged at average prices of approximately $85.35 and $6.45. For 2014, we have 2,090 Bbl/d of oil and 7,544 MMBtu/d of natural gas hedged at average prices of approximately $84.58 and $6.30.  For 2015, we have 2,000 Bbl/d of oil and 3,398 MMBtu/d of natural gas hedged at average prices of $87.40 and $5.52.





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 2011. 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.





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. 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:




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 Table Of Contents





·
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 “Note 2 — Summary of Significant Accounting Policies” of the Notes to the Consolidated Financial Statements in this report for a discussion of additional accounting policies and estimates made by management.





Proved Oil and Natural Gas Reserve Quantities





Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates, including DD&A expense and the full cost ceiling limitation. Proved oil and gas reserves are the estimated quantities of oil and 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. Miller & Lents, Ltd., our independent reserve engineering firm, will prepare a reserve report as of December 31 of each year, and we will prepare internal estimates of our proved reserves as of June 30 of each year. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines and Miller & Lents, Ltd. adheres to the same guidelines when preparing their reserve reports. 
 Assumptions used by independent petroleum 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.





Miller and Lents, Ltd. 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 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.




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 Table Of Contents





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.





A decline of proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. 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, if the SEC prices used for our December 31, 2010 reserve report had been $10.00 less per Bbl and $1.00 less per MMBtu, then the standardized measure of our estimated proved reserves as of December 31, 2010 would have decreased by approximately $109.8 million, from $498.4 million to $388.6 million.


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 natural gas and oil properties are capitalized. Exploration and development costs include dry-well costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding natural gas and oil reserves. Amortization of natural gas and oil properties is provided using the unit-of-production method based on estimated proved natural gas and oil reserves. Sales and abandonments of natural gas and oil properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and estimated proved natural gas and oil reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the reserve quantities of a cost center.


Depreciation, Depletion and Amortization





The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion 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 ten percent negative revision to proved reserves as of December 31, 2010 would increase the DD&A rate by approximately 0.02%. This represents an increase of DD&A expense of $1.88 per Boe, or a change from $16.91 to $18.79 per Boe for the period from December 22, 2010 through December 31, 2010. This estimated impact is based on current data as of December 31, 2010 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 price volatility and other market risks associated with our oil and natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions, all of which are lenders in our credit facility. 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.




A hypothetical 1% increase or decrease in the market prices related to our commodity derivative contracts would increase or decrease the fair values of our liability as of December 31, 2010 by $4.1 million.  This sensitivity was calculated without regards to any applicable credit risk adjustments.




Asset Retirement Obligation
  The initial estimated retirement obligation associated with oil and natural gas properties is recognized as a liability, with a corresponding increase in the carrying value of oil and natural gas properties. Amortization expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.
  Revenue Recognition and Natural Gas Balancing
  Oil and natural gas revenues are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. We and our predecessor account for oil and natural gas production imbalances using the sales method, whereby we and our predecessor recognize revenue on all natural gas and oil sold to our customers notwithstanding the fact that its ownership may be less than 100% of the oil and natural gas sold. Liabilities are recorded for imbalances greater than our respective proportionate shares of remaining estimated and oil natural gas reserves.
  Predecessor’s Unevaluated Properties
  The balance of unevaluated properties consists of capital costs incurred for undeveloped acreage, wells and production facilities in progress and wells pending determination, together with capitalized interest costs for these projects. These costs are initially excluded from the Predecessor’s amortization base until the outcome of the project has been determined or, generally, until it is known whether proved reserves will be assigned to the property. The Predecessor assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Predecessor assesses properties on an individual basis or as a group if properties are individually insignificant. The Predecessor’s assessments include consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The Predecessor estimates substantially all of its costs classified as unproved as of the balance sheet date will be evaluated and transferred within a five year period from the date of acquisition, contingent on its capital expenditures and drilling programs.


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 Table Of Contents


RESULTS OF OPERATIONS





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).




Partnership


PredecessorDecember 22

to

December 31,

2010


January 1

to

December 21,

2010


Year

Ended

December 31,

2009


Year

Ended

December 31,

2008RevenuesOil sales

$
2,217


$
165,565


$
41,188


$
170,716Natural gas sales


551



66,014



21,592



53,755NGLs sales


246



12,993



7,043



8,994Processing and other


-



8,814



2,978



47,605Total Revenue


3,014



253,386



72,801



281,070Operating ExpensesLease operating expenses


734



76,512



33,328



90,424Production and other taxes


192



17,657



7,587



14,566Processing and transportation


13



11,673



3,926



12,229Inventory adjustment


-



2,566



-



-Total production expenses


939



108,408



44,841



117,219Purchase of natural gas


-



-



-



13,960Impairment of oil and gas properties


-



-



28,338



451,440Depreciation, depletion and amortization


913



66,482



16,993



49,309Accretion of asset retirement obligations


25



3,674



3,585



3,004Management fees


-



10,486



12,018



12,018Offering costs


-



5,148



-



-Bargain purchase gain


-



-



(1,200
)


-General and administrative and other


280



26,893



19,279



14,703Total operating expenses


2,157



221,091



123,854



661,653Operating income (loss)


857



32,295



(51,053
)


(380,583
)Other income (expense):Equity in earnings of Ute Energy, LLC


-



3,782



2,675



(3,010
)Dividends on investment in marketable equity securities


-



-



233



579Gain (loss) on investment in marketable equity securities


-



-



394



(7,608
)Gain (loss) on commodity derivative contracts


(7,694
)


13,577



(63,120
)


134,655Gain on equity share issuance


-



4,064



-



-Interest expense


(304
)


(22,179
)


(3,716
)


(12,417
)Other income (expense)


-



482



(645
)


-Total other income (expense), net


(7,998
)


(274
)


(64,179
)


112,199Income (loss) before income taxes


(7,141
)


32,021



(115,232
)


(268,384
)Income tax benefit (expense), net


42



(108
)


(182
)


(149
)Net income (loss)

$
(7,099
)

$
31,913


$
(115,414
)

$
(268,533
)Production data:Oil (MBbls)


26



2,172



739



1,753Natural gas (MMcf)


141



14,754



5,359



5,590Natural gas liquids (MBbls)


4



282



207



139Total (Mboe)


54



4,913



1,838



2,824Average Net Production (Boe/d)


5,352



13,839



5,038



7,736Average sales price per unit(1):Oil (Per Bbl)

$
85.27


$
76.23


$
55.74


$
97.40Natural gas (per Mcf)

$
3.91


$
4.47


$
4.03


$
9.62Natural gas liquids (Per Bbl)

$
61.50


$
46.07


$
34.02


$
64.70Average unit cost per Boe:Lease operating expense

$
13.59


$
15.57


$
18.13


$
32.02Production and other taxes

$
3.56


$
3.59


$
4.13


$
5.16Management fees

$
-


$
2.13


$
6.54


$
4.26Depreciation, depletion and amortization

$
16.91


$
13.53


$
9.25


$
17.46General and administrative expenses

$
5.19


$
5.47


$
10.49


$
5.21




(1)
Does not include impact of derivative instruments.




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 Table Of Contents


Partnership’s Results of Operations
  We completed our IPO on December 22, 2010 with net assets of $223.7 million contributed to us by the Fund and included in our consolidated financial statements at the Fund’s book value as a transaction between entities under common control. The book value of net assets we received primarily includes $444.7 million of cost basis of oil and gas properties, $200 million of debt assumed from the Fund and asset retirement obligations of $18.3 million. Our operating results for the ten day period from December 22, 2010 to December 31, 2010 are presented below.


Period from December 22, 2010 through December 31, 2010





We recorded a net loss of $7.1 million during the period from December 22, 2010 through December 31, 2010.This net loss was primarily driven by a net loss on commodity derivative contracts of $7.7 million and interest expense of $0.3 million partially offset by our operating income of $0.9 million.





Sales Revenues.Sales revenues of $3.0 million for the period consisted of oil and condensate sales of $2.2 million, natural gas sales of $0.6 million and NGL sales of $0.2 million. Oil sales volumes were 25,909 Bbls and the average sales price was $85.58 per Bbl. Natural gas sales volumes were 141,209 Mcf and the average sales price was $3.90 per Mcf. NGL sales volumes were 4,079 Bbls and the average sales price was $60.42 per Bbl. Total average sales price was $56.32 per Boe. Production for the 10-day period was 5,352 Boe/d. 52% of sales were from the Permian area, 23% from Ark-La-Tex, 11% from Mid-Continent and 14% from Gulf Coast.





Effects of Commodity Derivative Contracts.Due to increases in oil and natural gas prices, we recorded a loss from our commodity derivatives program during the period of $7.7 million, composed of a realized loss of $0.3 million and an unrealized loss of $7.4 million.





Production Expenses.Our production expenses were $0.9 million for the period, consisting of $0.7 million in lease operating expenses or $13.71 per Boe and $0.2 million in production and other taxes or $3.59 per Boe.  67% of our operating expenses were from the Permian area.





Depreciation, Depletion and Amortization Expenses.Our depreciation, depletion and amortization expenses were $0.9 million, or $17.06 per Boe produced during the period.




General and Administrative and Other Expenses.Our general and administrative and other expenses were $0.3 million, or $5.19 per Boe. This consisted of $0.3 million of non-cash allocated general and administrative costs from the Fund of which only $0.1 million will be paid in cash in the form of an administrative services fee. See “Summary of Significant Accounting Policies” included under Note 2 to our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report for a discussion of our general and administrative expenses.





Interest Expense, net.Interest expense, related to the $225 million of borrowings under our new credit facility incurred in connection with our IPO, was $0.3 million during the period.





Predecessor’s Results of Operations





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





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





·
The following significant acquisitions by our Predecessor:


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


·
The acquisition of 80 producing natural gas wells located in Arkansas and Louisiana for $48.7 million in January 2009.


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


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


·
The period of 2010 is being presented for 355 days rather than a full year as a result of the IPO transaction on December 22, 2010. For ease of discussion, this 355 day period is at times referred to as the 2010 period.




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





Period From January 1, 2010 to December 21, 2010 Compared to the Year Ended December 31, 2009





Our Predecessor recorded net income of $31.9 million in the 355-day period from January 1, 2010 through December 21, 2010 compared to a net loss of $115.4 million for the year ended December 31, 2009. This increase was primarily driven by increased commodity prices, gains on commodity derivatives, impairment expense in 2009, the additional production associated with the Denbury acquisition and the revitalization of the Jay field.





Sales Revenues.Revenues for the 2010 period increased significantly as compared to 2009, from $72.8 million to $253.4 million due to higher production volumes associated with the Denbury properties and the Jay field, as well as higher commodity prices. Increased sales volumes for oil, natural gas and NGLs resulted in increases in revenues of $79.9 million, $37.8 million and $2.6 million. Increased average sales prices for oil, natural gas and NGL prices resulted in increases in revenues of $44.5 million, $6.6 million and $3.4 million. Processing and other revenues increased by $5.8 million primarily from an increase in sulfur revenues due to higher gas sales volumes.





Our Predecessor’s sales volumes for the 2010 period were 2,172 MBbls of oil, 282 MBbls of NGLs and 14,754 MMcf of natural gas. On an equivalent net basis, the period’s sales volumes were 4,913 MBoe, or 13,839 Boe/d. In comparison, our Predecessor’s sales volumes for 2009 were 739 MBbls of oil, 207 MBbls of NGLs and 5,359 MMcf of natural gas. On an equivalent net basis, 2009 sales volumes were 1,838 MBoe, or 5,038 Boe/d. The primary drivers behind the increase in overall sales volumes were the Denbury Acquisition completed in May 2010 and restarting of the Jay Field in December 2009.





Our Predecessor’s average sales price per Bbl for oil, excluding commodity derivative contracts, for the period ended December 21, 2010 was $76.23 per Bbl compared with $55.74 per Bbl for 2009. Average sales prices for natural gas, excluding commodity derivative contracts, also increased from $4.03 per Mcf in 2009 to $4.47 per Mcf during the period ended December 21, 2010. Average sales prices for NGLs also increased from $34.02 per Bbl in 2009 to $46.07 per Bbl during the 2010 period.





Effects of Commodity Derivative Contracts.Due to changes in oil and natural gas prices, our Predecessor recorded a net gain from its commodity derivatives program during the 2010 period of $13.6 million, composed of a realized gain of $5.4 million and an unrealized gain of $8.2 million. In contrast, our Predecessor recorded a net loss from its commodity hedging program in 2009 of $63.1 million, composed of a realized gain of $48.0 million, offset by an unrealized loss of $111.1 million.





Production Expenses.Our Predecessor’s lease operating expenses increased $43.2 million from $33.3 million, or $18.13 per Boe, in 2009 to $76.5 million, or $15.57 per Boe, during the 2010 period comprising a $55.8 million increase due to additional volumes from the Denbury acquisition and Jay field revitalization, partially offset by a $12.6 million decrease from lower unit costs associated with the Denbury properties. Production and other taxes increased from $7.6 million, or $4.13 per Boe, in 2009 to $17.7 million, or $3.59 per Boe, for the 2010 period, primarily due to the increase in revenues discussed above. Processing and transportation expenses increased from $3.9 million in 2009 to $11.7 million for the 2010 period, primarily due to natural gas imbalances recognized during the 2010 period of $5.3 million. The Predecessor also recognized an inventory write-off during the 2010 period of $2.6 million.





Impairment Expense.Our Predecessor recorded a substantial impairment under the full cost ceiling test of $28.3 million in 2009, predominantly as a result of the low oil and natural gas price environment at the end of 2009 and as a result of the decision to shut in the Jay Field during this period. There was no similar impairment for the 2010 period.





Depreciation, Depletion and Amortization Expenses.Our Predecessor’s depreciation, depletion and amortization expenses also increased significantly from $17.0 million, or $9.25 per Boe produced, in 2009 to $66.5 million, or $13.53 per Boe produced during the 2010 period. Higher total production volume level and higher relative capitalized costs, primarily due to the Predecessor’s acquisition of the Denbury properties, were the primary reasons for the increases.




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Management fees.Our Predecessor’s management fees decreased by $1.5 million for the 2010 period compared to 2009 based on adjustments in 2010 for previous overpayments.





General and Administrative and Other Expenses.Our Predecessor’s general and administrative and other expenses were $19.3 million, or $10.49 per Boe produced, in 2009 compared to $26.9 million, or $5.47 per Boe produced, for the 2010 period. General and administrative and other expenses increased by $3.3 million due to the growth of the business related to the Denbury acquisition, yet decreased on a per Boe basis as a result of additional production from the Denbury assets. General and administrative expenses in the 2010 period included $3.5 million in amortization of equity awards.  Other costs included $1.2 million in acquisition evaluation costs and $0.2 million in other expenses for the 2010 period compared to $0.6 million in acquisition evaluation costs for 2009.




Ute Energy, LLC. Our Predecessor's equity investment in Ute Energy, LLC resulted in an increase in other income of $5.2 million, comprising a $1.1 million increase in equity earnings and a $4.1 million gain associated with a recapitalization of its equity investment.





Interest Expense, net.The increase in interest expense from $3.7 million in 2009 to $22.2 million for 2010 period was primarily due to net losses on interest rate derivatives of $7.4 million and an increase in interest on our Predecessor’s credit facilities of $11.1 million from additional debt outstanding in the 2010 period related to the Denbury acquisition.




Other. Our Predecessor bore the IPO costs of $5.1 million in 2010. Our Predecessor also recognized a bargain purchase gain of $1.2 million for 2009 in respect of the acquisition of the Shongaloo properties.





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





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





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





Our Predecessor’s sales volumes for 2009 were 739 MBbls of oil, 207 MBbls of NGLs and 5,359 MMcf of natural gas. On an equivalent net basis, 2009 sales volumes were 1,838 MBoe, or 5,038 Boe/d. In comparison, our Predecessor’s production volumes for 2008 were 1,753 MBbls of oil, 139 MBbls of NGLs and 5,590 MMcf of natural gas. On an equivalent net basis, 2008 production was 2,824 MBoe, or 7,736 Boe/d. The primary driver behind the decrease in overall production volumes was the Jay Field shut-in.





Our Predecessor’s average sales price per Bbl for oil, excluding commodity derivative contracts, for 2009 was $55.74 per Bbl compared with $97.40 per Bbl for 2008. Average sales prices for natural gas, excluding commodity derivative contracts, also decreased from $9.62 per Mcf in 2008 to $4.03 per Mcf in 2009. Average sales prices for NGLs also decreased from $64.70 per Bbl in 2008 to $34.02 per Bbl in 2009.





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





Production Expenses.Our Predecessor’s lease operating expenses decreased $57.1 million from $90.4 million, or $32.02 per Boe, in 2008 to $33.3 million, or $18.13 per Boe, in 2009, primarily as a result of the Jay Field shut-in. The Jay Field had a higher average $/Boe production expense than the Predecessor’s other operations during 2008. Production and other taxes decreased from $14.6 million, or $5.16 per Boe, in 2008 to $7.6 million, or $4.13 per Boe, in 2009 primarily due to the decrease in revenues discussed above. On a per Boe basis, production taxes decreased period over period primarily due to the decrease in sales prices of oil and natural gas sold, as discussed above. Processing and transportation expenses decreased from $12.2 million in 2008 to $3.9 million in 2009.





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




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Depreciation, Depletion and Amortization Expenses.Our Predecessor’s depreciation, depletion and amortization expenses also decreased significantly from $49.3 million, or $17.46 per Boe produced, in 2008 to  $17.0 million, or $9.25 per Boe produced, in 2009. The decrease is a direct result of the full cost ceiling impairment recognized in 2008, which decreased the carrying amount of our Predecessor’s oil and natural gas properties subject to depletion by $451.4 million.





General and Administrative and Other Expenses.Our Predecessor’s general and administrative and other expenses increased from $14.7 million, or $5.21 per Boe produced, in 2008 to $19.3 million, or $10.49 per Boe produced, in 2009 primarily as a result of the move of our Predecessor’s headquarters from Denver to Houston.




Ute Energy, LLC. OurPredecessor's other income increased by $5.7 million due to a change from a loss to a profit in equity earnings.





Interest Expense, net.The decrease in interest expense from $12.4 million in 2008 to $3.7 million in 2009 was primarily due to a decrease in net losses on interest rate derivatives of $4.9 million and a decrease in net interest expense of $3.8 million primarily due to the Predecessor's debt repayments in October 2008 .





Other. Our Predecessor had $14 million in nonrecurring purchases of natural gas in 2008. Our Predecessor had a loss on investments in marketable securities of $7.6 million in 2008 compared to a gain on these investments of $0.4 million in 2009.




Liquidity and Capital Resources





Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness 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, the issuance of additional units by the Partnership and access to the debt markets. The capital markets continue to experience volatility. Many financial institutions have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to current credit conditions includes our credit facility, cash investments and counterparty performance risks. Continued 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 hedges under lower commodity prices, which could have a material adverse effect on our results of operation. We sell our oil and natural gas 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 price associated with a portion of our expected oil and natural gas volumes through 2015 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 estimated oil and natural gas production over a three-to-five year period at a given point in time. As opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative contracts in connection with material increases in our estimated reserves and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. See “Quantitative and Qualitative Disclosures About Market  Risk — Commodity Price Risk.” 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, 2010 our liquidity of $77.2 million consisted of $2.2 million of available cash, and $75 million of available borrowings under our credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility. As of December 31, 2010, our $750 million credit facility had borrowing capacity of $75 million ($300 million borrowing base less $225 million of outstanding borrowings under our credit facility). The borrowing base will be redetermined on May 1 and November 1 of each year, beginning on May 1, 2011 by the administrative agent of our credit facility. In addition, we may request additional capacity for acquisitions at a minimum of the lesser of $50 million or ten percent of the existing borrowing base at the time.




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A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands. As of December 31, 2010, we had no letters of credit outstanding.





Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 7 and Note 9 of the notes to Consolidated Financial Statements included in this Annual Report.





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, 2010, we had a positive working capital balance of $3.1 million.




Capital Expenditures





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





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




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The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our new credit facility will exceed our planned capital expenditures and other cash requirements for 2011. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production. 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.





Credit Agreement





On December 17, 2010, subject to the completion of our IPO, we entered into a five-year Credit Agreement which includes a $750 million revolving credit facility with an initial borrowing base of $300 million. The borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, NGL and oil reserves, which will take into account the prevailing natural gas, NGL and oil prices and associated differentials at such time which is then adjusted for the impact of our commodity derivative contracts. In the future, we may be unable to access sufficient capital under our new credit facility as a result of (i) a decrease in our borrowing base due to subsequent borrowing base redeterminations, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.





A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under 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 2011.





Borrowings under the Credit Agreement are secured 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, at either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. A hypothetical increase of 100 basis points in the underlying interest rate would increase our annual interest expense by $2.3 million based on our outstanding borrowings as of December 31, 2010.





The Credit Agreement requires us to maintain a Leverage Ratio (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 its assets; make certain investments, acquisitions or other restricted payments (including a prohibition on our ability to pay distribution to its unitholders if its borrowing base usage exceeds 95%); modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. The 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, 2010, we were in compliance with all of the facility’s financial covenants. In addition, the Credit Agreement requires us to deliver audited financial statements within 105 days after year-end and reviewed quarterly financial statements within 45 days after quarter-end.  We did not provide our audited financial statements by April 15, 2011 for which we sought and received a waiver to extend this reporting requirement by 30 days.




74




As of December 31, 2010, we had $225.0 million outstanding under the facility.





Commodity Derivative Contracts





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





The Fund assigned certain commodity derivative financial instruments to us, and we intend to continue to enter into commodity derivative instruments to reduce the impact of oil and natural gas price volatility on our operations. The commodity derivative contracts assigned to us by the Fund are swaps based on NYMEX oil and natural gas prices. As of December 31, 2010, we had in place oil and natural gas swaps covering significant portions of our estimated oil and natural gas production through December 31, 2015.


We use swaps as a mechanism for managing commodity price risks whereby we pay the counterparty floating prices and receive fixed prices from the counterparty. By entering into the swap agreements, we will mitigate the effect on our cash flows of changes in the prices we receive for our oil and natural gas production. These transactions are settled based upon the NYMEX-WTI price of oil and NYMEX-Henry Hub price of natural gas. The following table summarizes our oil and natural gas swaps as of December 31, 2010 for the periods indicated through December 31, 2015.


Commodity

Index

2011


2012


2013


2014


2015Oil position:Hedged volume (Bbls/d)

WTI


2,238



2,039



2,076



2,090



2,000Average price ($/Bbls)



$
85.00


$
85.25


$
85.35


$
84.58


$
87.40Natural gas position:Hedged volume (MMBtu/d)

NYMEX


9,178



8,192



7,474



7,544



3,398Average price ($/MMbtu)



$
7.26


$
6.45


$
6.45


$
6.30


$
5.52







For more information on the oil and natural gas swaps and swap prices and resulting adjusted swap prices in place as of December 31, 2010, See “Item 7A. Quantitative and Qualitative Disclosure About Market Risk."





Counterparty Exposure





As of December 31, 2010, our open commodity derivative contracts were in a net payable position. All of our commodity derivative contracts are with major financial institutions who are also lenders under our credit facility. 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 under our derivative instruments with certain of our counterparties, we have properly presented all asset and liability positions without netting. As of December 31, 2010, all of our counterparties have performed pursuant to their commodity derivative contracts.




The following table presents our asset and liability positions with our counterparties both before and after credit risk adjustments as of December 31, 2010:
  Gross


Credit Risk Adjustment


AdjustedAssets


18,252



(205
)


18,047Liabilities


(28,449
)


1,572



(26,877
)Net


(10,197
)


1,367



(8,830
)




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


PredecessorDecember 22


January 1through


throughDecember 31,


December 21,


Year Ended December 31,2010


2010


2009


2008Net cash provided by (used in):Operating activities

$
(283
)


95,945


$
64,907


$
75,282Investing activities


-



(956,877
)


(55,458
)


(137,161
)Financing activities


2,478



903,448



(13,328
)


30,240
  Operating Activities
 
 Partnership
 
 Our cash flows used in operating activities were $0.3 million primarily for interest paid under our Credit Agreement.
 
 Predecessor
 
 The Predecessor’s cash flows from operating activities provided $95.9 million for the period of January 1, 2010 to December 21, 2010 and $64.9 million for the year ended December 31, 2009. The increase in cash provided by operating activities was primarily due to increases in net income caused by increased production levels from the Predecessor’s acquisitions of oil and natural gas properties in 2010 as well as improved prices period over period.
 
 The Predecessor’s cash flows from operations provided $64.9 million in 2009 compared with $75.3 million in 2008 resulting in decrease in cash provided for 2009 due to a production shut-in at the Jay Field and decreased oil and natural gas price.
 
 Investing Activities
 
 Predecessor
 
 The Predecessor’s 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.
 
 The Predecessor’s cash used in investing activity was $956.9 million for the period of January 1, 2010 to December 21, 2010 and $55.5 million for the year ended December 31, 2009. The increase in net cash outflow period over period was primarily due to the Denbury acquisition in 2010 and nonrecurring proceeds from the sale of noncore oil and gas properties in 2009.
 
 The Predecessor’s cash used in investing activity was $55.5 million for the 2009 and $137.2 million for 2008. The decrease in cash outflow was primarily due to the shut-in of the Jay Field during 2009, a nonrecurring initial investment in Ute Energy in 2008 and a decrease in net cash outflow from investments in marketable securities period over period, partially offset by an increase in cash outflow for the 2009 Shongaloo acquisition.
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 Financing Activities
 
 Partnership
 
 Our cash flows provided by financing activities of $2.5 million comprised total inflows of $505.1 million and total outflows of $502.6 million. Our financing cash inflows were $279.8 million net proceeds from our IPO, $225 million in borrowings under our new credit facility and $0.3 million in intercompany financing from the Fund. Our financing cash outflows were $300 million of distributions to the Fund, $200 million in repayments of debt assumed from the Fund and $2.7 million of deferred financing costs incurred in connection with our new credit facility.
 
 Predecessor
 
 The Predecessor’s cash flows from financing activities comprised a $903.4 million in cash provided for the period of January 1 to December 21, 2010 and ($13.3) million in cash used for the year ended December 31, 2009. The increase in cash provided by financing activities in 2010 was due primarily to cash calls received from investors and borrowings under a new credit facility to fund the Denbury acquisition partially offset by the repayment of the previous credit facility.
 
 The Predecessor’s cash flows from financing activities comprised ($13.3) million in cash used for 2009 and $30.2 million in cash provided for 2008. The decrease in cash provided by financing activities period over period was due primarily to nonrecurring capital calls partially offset by nonrecurring repayments of debt both of which occurred in 2008.
 
 Capital Requirements
 
 We currently expect 2011 spending for the development of our oil and natural gas properties to be approximately $12.5 million.
 
 We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.4125 per unit per quarter ($1.65 per common unit on an annualized basis). Based on the number of common units, subordinated units and general partner units outstanding as of April 15, 2011, distributions to all of our unitholders at the minimum quarterly distribution rate for  2011 would total approximately $59.2 million.
 We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisition of oil and natural gas properties in 2011 through a combination of cash, borrowings under our credit facility and the issuance of equity or debt securities.
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  Contractual Obligations
 
 In the table below, we set forth our contractual cash obligations as of December 31, 2010. 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 PeriodTotal


Less than 1 Year


1 - 3 Years


4 - 5 Years


After 5 YearsTotal debt (1)

$
225,000


$
-


$
-


$
225,000


$
-Estimated interest payments (2)


50,430



9,608



20,416



20,406



-Asset retirement obligations (3)


18,288



1,848



359



2,030



14,051Total

$
293,718


$
11,456


$
20,775


$
247,436


$
14,051
  (1)
Total balance of our senior secured credit facility will mature in December 2015.
 (2)
Amounts represent cash payments for interest based on the debt outstanding and unused portion of our credit facility as of December 31, 2010.  Rates used to calculate these estimated payments include a 0.5% commitment fee on the $75 million unused portion of the facility, 2.77% for the period from January 1 to February 28, 2010 and 4.37% for the remaining term of the facility.
 (3)
Present value of obligations at December 31, 2010.
 
 Off–Balance Sheet Arrangements
 
 As of December 31, 2010, we had no off–balance sheet arrangements.
 
 Recently Issued Accounting Pronouncements
 
 For a discussion of recent accounting pronouncements that will affect us, see “Significant Accounting Policies” included under Note 2 to our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report.
 
 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.
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 Swaps.In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis.
 
 We use swaps as a mechanism for managing commodity price risks whereby we pay the counterparty floating prices and receive fixed prices from the counterparty. By entering into the swap agreements, we will mitigate the effect on our cash flows of changes in the prices we receive for our oil and natural gas production. These transactions are settled based upon the NYMEX-WTI price of oil and NYMEX-Henry Hub price of natural gas.
 
 The following table summarizes our oil and natural gas swaps as of December 31, 2010 for the periods indicated through December 31, 2015.
 Commodity

Index

2011


2012


2013


2014


2015Oil position:Hedged volume (Bbls/d)

WTI


2,238



2,039



2,076



2,090



2,000Average price ($/Bbls)



$
85.00


$
85.25


$
85.35


$
84.58


$
87.40Natural gas position:Hedged volume (MMBtu/d)

NYMEX


9,178



8,192



7,474



7,544



3,398Average price ($/MMbtu)



$
7.26


$
6.45


$
6.45


$
6.30


$
5.52
 
 A hypothetical 1% increase or decrease in the market prices related to our commodity derivatives contracts would increase or decrease the fair values of our liability as of December 31,2010 by $ 4.1 million. The sensitivity was calculated without regards to any applicable credit risk adjustments.
 Interest Rate Risk
 
 As of December 31, 2010, we had debt outstanding of $225 million, with a weighted average interest rate of LIBOR plus 2.5%, or 2.8%. On February 28, 2011, the Predecessor novated interest rate swaps to the Partnership to mitigate our exposure to interest rate risk as we expect interest rates to continue to be volatile and unpredictable. Our risk management 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. Please refer to Item 8. Consolidated Financial Statements—Note 5, “Derivative Activities” for additional information.
 
 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 “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, 2010, our open commodity derivative contracts were in a net payable position with a fair value of ($8.8) 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 loss.
  While we do not require our customers to post collateral and do not have a formal process in place to evaluate and assess the credit standing of our significant customers or the counterparties on our derivative contracts, we do evaluate the credit standing of our customers and such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating and latest financial information or, in the case of a customer with which we have receivables, reviewing their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative contracts currently in place are lenders under our Predecessor’s credit facilities, with investment grade ratings and we are likely to enter into any future derivative contracts with these or other lenders under our new credit facility that also carry investment grade ratings. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.
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 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 Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our principal executive officer and 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, 2010. 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 under the Exchange Act 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 and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. In light of the material weaknesses described below, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2010. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Notwithstanding the material weaknesses, management concluded that the financial statements included in this Annual Report on Form 10-K presents fairly, in all material respects, the financial condition, results of operations and cash flows for all periods presented.
 
 The lack of adequate staffing levels and communication throughout the organization  resulted in insufficient time spent on review and approval of certain information used to prepare our Predecessor’s and the Partnership's financial statements.  In addition, we did not design and operate effective controls over the month end closing process to allow for management's review on a timely, consistent and effective basis.  That combined with an IT environment that lacks segregation of duties, insufficient controls over change management processes for the related financial reporting systems, and a lack of integration of key systems all contributed to material weaknesses in the overall control environment. The lack of adequate staffing and insufficient supervision throughout the organization also resulted in the lack of design of proper policies and procedures over several control activities, as further described below, which represent individual material weaknesses at the control activity level. These material weaknesses contributed to multiple audit adjustments.  The following are the individual control activity level material weaknesses:
 
 ·
We did not design and operate effective controls to ensure the completeness and accuracy of the inputs with respect to the full cost ceiling impairment test and depreciation, depletion and amortization calculations, resulting in audit adjustments in 2009 and 2010.
 
 ·
We did not design and operate effective controls over the calculation and review of the nonperformance risk adjustment related to the valuation of derivative contracts, resulting in audit adjustments in 2009 and 2010.
 
 ·
We did not design and operate effective controls to ensure that gas imbalance liabilities were appropriately recorded, resulting in audit adjustments in 2010.
 
 ·
We did not design and operate effective controls over the management of suspended revenue and revenue clearing balances and outside owners’ interests accruals, resulting in audit adjustments in 2010.
 
 ·
We did not design and operate effective controls to ensure that inventory balances were complete and accurate and movements recorded on a timely basis, resulting in audit adjustments in 2010.
 
 ·
We did not design and operate effective controls over acquisitions to ensure all material assets, liabilities, revenues and expenses were identified and recorded, resulting in audit adjustments in 2010.
 
 ·
We did not design and operate effective controls to ensure that the accounting for the IPO transaction and the associated conveyance accounting had been correctly accounted for, resulting in audit adjustments in 2010.
 
 ·
We did not design and operate effective controls to ensure that executive and management compensation arrangements had been identified and the related expenses appropriately recorded, resulting in audit adjustments in 2010, some of which were out-of-period adjustments.
 
 In response, we have begun the process of evaluating our internal control over financial reporting, although we are in the early phases of our review and will not complete our review until later in 2011. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weaknesses previously identified. Each of the material weaknesses described above could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our annual or interim consolidated financial statements that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses described above or avoid potential future material weaknesses.
 
 This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Partnership’s independent registered public accounting firm due to a transition period established by SEC rules for newly public entities. A report of management’s assessment regarding internal control over financial reporting is not required until we file our annual report for the year ended December 31, 2011.  If we are determined to be an accelerated filer under the applicable SEC rules, an attestation report from the Partnership's independent registered public accounting firm would also be required for our annual report for the year ended December 31, 2011.
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  Changes in Internal Control over Financial Reporting.
 
 There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the period covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
  ITEM 9B. OTHER INFORMATION
 
 None.
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  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. References to our officers, directors and employees are references to the officers, directors and employees employed by 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.  Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation.  Our general partner is owned by entities controlled by affiliates of Quantum Energy Partners and the Fund.
  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, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made 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 will offer an enterprise-level risk assessment to the board of directors at least once every year.
  Directors and Executive Officers
  The following table sets forth certain information regarding the current directors and executive officers of our general partner. Directors are elected for one-year terms.
  Name

Age

Position with our General PartnerAlan L. Smith


48

Chief Executive Officer and DirectorJohn H. Campbell, Jr


53

President, Chief Operating Officer and DirectorCedric W. Burgher


50

Chief Financial OfficerGregory S. Roden


52

Vice President, Secretary and General CounselHoward K. Selzer


54

Chief Accounting OfficerToby R. Neugebauer


40

DirectorDonald E. Powell (1)


69

DirectorStephen A. Thorington (2)


55

DirectorS. Wil VanLoh, Jr.


40

DirectorDonald D. Wolf


67

Chairman of the Board
 
 (1)     Chairman of the conflicts committee and member of the audit committee.
 (2)     Chairman of the audit committee and member of the conflicts committee.
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  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. Smithis the Chief Executive Officer and a member of the board of directors of our general partner. Mr. Smith also serves as a Venture Partner with Quantum Energy Partners. Prior to becoming the Chief Executive Officer of Quantum Resources Management in 2009, Mr. Smith served as a Managing Director with Quantum Energy Partners and as Chairman of Chalker Energy Partners II, LLC, both beginning in 2006. From 2003 until 2006, Mr. Smith served as the President and CEO of Chalker Energy Partners I, LLC, a private oil and natural gas exploration and production company he co-founded, which was funded by Quantum Energy Partners. From 2001 until 2003, Mr. Smith served as the Vice President of Business Development at Ocean Energy, Inc. and from 1999 to 2001 he was the Asset Manager for an onshore business unit at Ocean Energy. Prior to 1999, Mr. Smith served in positions of increasing responsibility at XPLOR Energy, Inc., Ryder Scott Company, Burlington Resources and Vastar Resources/ARCO Oil and Gas Company. From June 2006 to June 2007, Mr. Smith served on the board 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 a board member of Vantage Energy, LLC since 2006.  He serves as a board member for the Southeastern Region IPAA, an advisory board member of the A&D Watch, a Hart’s publication, and also serves in an advisory capacity to the Texas Tech Department of Petroleum Engineering. We believe that Mr. Smith’s extensive experience in the energy industry and his relationships with Quantum Resources Management and Quantum Energy Partners, particularly his service as the Chief Executive Officer of Quantum Resources Management, bring important experience and skill to the board of directors.
 
 John H. Campbell, Jr.is the President and Chief Operating Officer and a member of the board of directors of our general partner. Mr. Campbell also serves as a 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, 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 is theChief Financial Officer of our general partner.  Mr. Burgher is also the Interim Chief Financial Officer of the Quantum Resource Funds.  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 certain entities of Chalker Energy Partners II and III, LLC.Prior to joining Quantum Energy Partners, Mr. Burgher served as Senior Vice President and Chief Financial Officer of KBR, Inc., a global engineering, construction and services company, from 2005 until 2008.  Prior to KBR, Mr. Burgher served as the Chief Financial Officer of Burger King Corporation, an international restaurant company, from 2004 to 2005.  Mr. Burgher worked for Halliburton Company, an oilfield services company, from 2001 to 2004, most recently as the Vice President and Treasurer and, prior to that, as the Vice President of Investor Relations.  He also previously held financial management positions with Enron, EOG Resources and Baker Hughes following several years in the banking industry.  Mr. Burgher has been a director of Taggart Global USA, LLC since 2007 and a director of NextCorp Capital Management, LC since 2008. Mr. Burgher is a Chartered Financial Analyst (CFA).
 
 Gregory S. Rodenis the Vice President and General Counsel of our general partner. Since 2009, Mr. Roden has served as Vice President and General Counsel of Quantum Resources Management. From 2005 to 2009, Mr. Roden was Senior Counsel for Devon Energy supporting their Southern and Gulf of Mexico Divisions. From 2003 to 2005, Mr. Roden worked for BP on various LNG regasification projects in the U.S. and in support of BP’s products trading floor. Mr. Roden served as Ocean Energy’s Assistant General Counsel for Onshore Domestic Operations from 2000 to 2003. Mr. Roden commenced his legal practice in 1992 as an oil and natural gas attorney specializing in acquisitions and divestitures with Akin, Gump, Strauss, Hauer and Feld, LLP. Prior to becoming an attorney, Mr. Roden worked from 1980 to 1989 for Exxon Company USA in various natural gas production, processing, marketing and management positions.
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 Howard K. Selzeris the Chief Accounting Officer of our general partner. Mr. Selzer is also Chief Accounting Officer for Quantum Resources Management. His primary responsibility is to oversee all of our accounting, financial reporting, tax and audit functions. Prior to joining Quantum Resources Management in 2009, Mr. Selzer worked for Terralliance Technologies, Inc. from 2007 to 2009, most recently as the Chief Financial Officer and, prior to that, as Chief Accounting Officer. From 2006 to 2007, Mr. Selzer was VP Finance and Administration of TGS-NOPEC. In addition, he served as CFO of Santos USA from 2003 to 2005. Prior to joining Santos, Mr. Selzer was with Enron Oil & Gas International, where he held the roles of Senior Director & Controller and Manager, Financial Reporting & Budgets from 1992 to 2003. Mr. Selzer worked and was most recently an International Petroleum Negotiator based in Paris, France for Elf Aquitaine from 1983 to 1992 and an International Petroleum Accountant for Cities Service Co. from 1981 to 1983. Mr. Selzer is a Certified Public Accountant.
  Toby R. Neugebaueris 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. Powellserves on the board of directors of our general partner. He has been a member of the board of directors of Bank of America Corporation since 2009 and a member of the board of directors of Stone Energy Corporation since 2008. Mr. Powell served as the Federal Coordinator of Gulf Coast Rebuilding from 2005 until 2008. Prior to 2005, Mr. Powell was the 18th Chairman of the Federal Deposit Insurance Corporation, where he served from 2001 until 2005. 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. Mr. Powell was selected to serve as a director because of his vast financial experience, which brings a unique and valuable experience to the Board.
  Stephen A. Thoringtonserves on the board of directors of our general partner. 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 and conflicts committees.
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 S. Wil VanLoh, Jr.is a member of the board of directors of our general partner. Mr. VanLoh is the President and Chief Executive Officer of Quantum Energy Partners, which he co-founded in 1998. Quantum Energy Partners manages a family of energy-focused private equity funds, with more than $5.7 billion of capital under management. Mr. VanLoh is responsible for the leadership and overall management of the firm. Additionally, he leads the firm’s investment strategy and capital allocation process, working closely with the investment team to ensure its appropriate implementation and execution. He oversees all investment activities, including origination, due diligence, transaction structuring and execution, portfolio company monitoring and support and transaction exits. Prior to co-founding Quantum Energy Partners, Mr. VanLoh co-founded Windrock Capital, Ltd., an energy investment banking firm specializing in providing merger, acquisition and divestiture advice to and raising private equity for energy companies. Prior to co-founding Windrock in 1994, Mr. VanLoh worked in the energy investment banking groups of Kidder, Peabody & Co. and NationsBank. Mr. VanLoh currently serves on the boards of a number of portfolio companies of Quantum Energy Partners, all of which are private energy companies. Mr. VanLoh also serves on the board of QA Global GP, LLC, which is the entity controlling the Fund. Mr. VanLoh served on the board of directors of the general partner of Legacy Reserves LP from its founding to August 1, 2007 and was also involved in the founding of Linn Energy, LLC. Mr. VanLoh has served as a board member and Treasurer of the Houston Producer’s Forum and on the Finance Committee of the Independent Petroleum Association of America (“IPAA”). We believe that Mr. VanLoh’s extensive experience, both from investing in the energy industry over the past thirteen years and serving as director for numerous private energy companies, brings important and valuable skills to the board of directors.
  Donald D. Wolf
 Composition of the Board of Directors
 
 QRE GP, LLC’s board of directors consists of seven 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.
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  Committees of the Board of Directors and Independence Determination
 QRE GP, LLC’s board of directors has established an audit committee and a conflicts committee.  The charters of both committees is 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 nominating, governance or compensation 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 and Powellsatisfy the NYSE and SEC requirements for independence.
  Audit Committee
 
 The audit committee consists of Messrs. Thorington (Chairman) and Powell, both of whom meet the independence and experience standards established by the NYSE and the Exchange Act. 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 held no meetings in 2010.
  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–approves 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) and Thorington, both 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. The conflicts committee held no meetings in 2010.
 
 Meetings and Other Information
 
 The board of directors held no meetings in 2010.
 
 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 QRE GP, LLC 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 QRE GP, LLC, we believe that during the year ended December 31, 2010 the officers and directors of QRE GP, LLC 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).
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 Corporate Code of Business Conduct and Ethics
 
 The corporate governance of QRE GP, LLC 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, 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. Our general partner has entered into a services agreement with Quantum Resources Management. Under the services agreement, through December 31, 2012, Quantum Resources Management will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. After December 31, 2012, in lieu of the quarterly administrative services fee, our general partner will reimburse Quantum Resources Management, on a quarterly basis, for the allocable expenses it incurs in its performance under the services agreement and we will reimburse our general partner for such payments to Quantum Resources Management. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated by Quantum Resources Management to its affiliates. Quantum Resources Management will have substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us.
 
 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, subject to reimbursement by our general partner to the extent provided under the services agreement.  Our general partner’s reimbursement for the compensation of its executive officers is governed by, and subject to the limitations of, the services agreement.  Please read “Certain Relationships and Related Party Transactions—Ownership in Our General Partner by the Management of the Fund—Services Agreement” for more information.
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 We commenced our business operations at the time of our initial public offering on December 22, 2010 and, therefore, we incurred no cost or liability with respect to compensation of our general partner’s executive officers, nor did our general partner accrue any liabilities for incentive compensation or retirement benefits for its executive officers, for fiscal years prior to 2010.  Other than the services our general partner’s executive officers provided to us in connection with our initial public offering, their activities in fiscal 2010 with respect to us were a minor consideration for Quantum Resources Management and the board of directors of our general partner in the determination of the compensation paid to such individuals.
 
 This compensation discussion and analysis, or CD&A, provides general information about the compensation paid to the executive officers of our general partner identified in the following table, who we refer to in this CD&A and the tables that follow as our “named executive officers.”
  Name

Principal PositionAlan L. Smith

Chief Executive OfficerJohn H. Campbell, Jr.

President and Chief Operating OfficerCedric W. Burgher

Chief Financial OfficerGregory S. Roden

Vice President, Secretary and General CounselHoward K. Selzer

Chief Accounting Officer
  Compensation Decisions for Fiscal 2010
 
 Our general partner’s board of directors has responsibility and authority for compensation-related decisions for our named executive officers in respect of their service to us. Quantum Resources Management, however, has responsibility and authority for compensation-related decisions for our named executive officers in respect of their service to the Fund or other entities.  In fiscal 2010, none of our named executive officers devoted a significant portion of their time to our business.  Therefore, Quantum Resources Management had responsibility and authority for compensation-related decisions for our named executive officers during fiscal 2010 other than certain awards granted to our named executive officers under our general partner’s long-term incentive plan (the “LTIP”) described below.  The portion of our named executive officers’ salaries, bonuses and benefit costs incurred by Quantum Resources Management that was allocated to us, as reflected in the Summary Compensation Table below, was based on the applicable production percentage determined by dividing the average daily production in MBoe/d for the Partnership by the total average combined daily production for the Partnership and the Fund, which was 29.96% for 2010 and capped at the amount of the administrative services fee under the services agreement for the period beginning on December 22, 2010, the date of the closing of our initial public offering, and ending on December 31, 2010.  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., each of whom are directors of our general partner.
 
 Compensation Expectations for 2011
 
 In fiscal 2011, Mr. Burgher will devote all of his time to our business once he ceases to serve as interim chief financial officer of the Fund following the hiring of a permanent replacement.  As a result, the board of directors of our general partner will have sole responsibility and authority for compensation-related decisions relating to Mr. Burgher.
 
 Mr. Burgher’s base salary (currently $275,000) is not included in the administrative services fee and after December 31, 2010, we will be obligated to reimburse our general partner for all payments it makes to Quantum Resources Management for the full amount of the annual salary of Mr. Burgher.  Please read “Certain Relationships and Related Party Transactions—Ownership in Our General Partner by the Management of the Fund—Services Agreement” for more information.  Additionally, both owners of our general partner have agreed to pay Mr. Burgher up to 0.75% of each owner’s share of any quarterly management incentive fee paid to our general partner during the period of his employment.  The portion of any quarterly management incentive fee paid to Mr. Burgher will not be an expense reimbursed by our general partner or us under the services agreement.
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 We expect that Mr. Burgher’s compensation for fiscal 2011 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 (primarily the ability to increase sustainable quarterly distributions to our unitholders), which will be based on a combination of our partnership’s performance and Mr. Burgher’s 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.
  In addition, as described below, our general partner has granted Messrs. Smith and Campbell restricted unit awards under the LTIP in 2011 as compensation for the services they are providing to our business.
  As we develop our business, we will 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 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 officer’s cash bonuses, if any, will reflect their relative contributions to achieving or exceeding annual goals of the partnership and the determination of specific individuals’ long-term incentive awards will be based on their expected contribution in respect of longer term performance objectives.
 
 Long-Term Incentive Plan Awards
 
 Our general partner has adopted the LTIP for employees, officers, consultants and directors of our general partner and its affiliates, including Quantum Resource Management, who perform services for us.  Each of our named executive officers is eligible to participate in the LTIP.  The LTIP provides 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, 2010, there are 1,670,560 common units that remain available for issuance under the LTIP.
 
 Upon the closing of our initial public offering, the board of directors of our general partner granted each of Messrs. Burgher, Roden and Selzer a $200,000 restricted unit award under the LTIP, for their services rendered in connection with the completion of our initial public offering.  These restricted units vest with respect to each of Messrs. Burgher, Roden and Selzer in equal one-third increments over a 36-month period (i.e., approximately 33.3% vest at each one-year anniversary of the date of grant, so that the restricted units will be 100% vested on December 22, 2013) provided that they have continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the date of grant through each applicable vesting date.  Because Mr. Burgher will devote all of his time to our business once he ceases to serve as the Chief Financial Officer of the Fund, he also received an additional grant of 75,000 restricted units in connection with the closing of our initial public offering as an employment inducement award.  As this portion of Mr. Burgher’s award is intended to serve a retention function, these restricted units vest in equal one-fifth increments over a 60-month period (i.e., 20% vest at each one-year anniversary of the date of grant, so that the restricted units will be 100% vested on December 22, 2015), provided that Mr. Burgher has continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the date of grant through each applicable vesting date.
  On March 9, 2011, the board of directors of our general partner granted each of Messrs. Smith and Campbell a $200,000 restricted unit award under their LTIP for the services they are providing to our business. These restricted units vest in equal one-third increments over a 36-month period (i.e., approximately 33.3% vest at each one-year anniversary of the date of grant, so that the restricted units will be 100% vested on March 9, 2014), provided they have continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the date of grant through each applicable vesting date.
 The restricted units granted to our named executive officers will become fully vested upon a change of control 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 our 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 LTIP awards, we intend to continue to primarily utilize restricted unit awards with UDRs.  These awards are intended to align the interests of key employees (including our named executive officers) with those of our unitholders.
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 Other Benefits
 
 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 a 401(k) plan and health, disability and life insurance. Employees provided to us under the services agreement, including our named executive officers, are entitled to the same basic benefits.  For the period between December 22, 2010 and December 31, 2010, Quantum Resource Management provided adollar-for-dollar matching contribution under the 401(k) plan on the first 3% of eligible compensation contributed to the plan.  In 2011, the Quantum Resource Management dollar-for-dollar matching contribution under the 401(k) plan moved to a Safe Harbor contribution of a dollar-for-dollar match on the first 3% of eligible compensation and 50% of the next 2% of eligible compensation contributed to the plan.A discretionary employer matching contribution may also be made under the 401(k) plan on behalf of those eligible employees who meet certain conditions and subject to certain limitations under applicable law.
 
 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.
 
 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, 2010.
  (3) (4) (5)Stock


All Other (6)


TotalName

Year

Salary(1)


Bonus(2)


Awards


Compensation


CompensationAlan L. Smith

2010

$
410


$
-


$
-


$
-


$
410Chief Executive OfficerJohn H. Campbell, Jr.

2010

$
410


$
-


$
-


$
-


$
410President and Chief Operating OfficerCedric W. Burgher

2010

$
7,535


$
1,413


$
1,702,550


$
-


$
1,711,498Chief Financial OfficerGregory S. Roden

2010

$
1,847


$
1,847


$
200,300


$
129


$
204,123Vice President, Secretary and General CounselHoward K. Selzer

2010

$
1,847


$
1,847


$
200,300


$
129


$
204,123Chief Accounting Officer
 
 (1)
Reflects the portion of the base salaries paid by Quantum Resources Management to each of our named executive officers that will be reimbursable by our general partner under the services agreement after December 31, 2012 (allocated based on the applicable production percentage, which was 29.96%  for 2010), prorated for the period beginning on December 22, 2010, the date of the closing of our initial public offering, and ending on December 31, 2010.  While this amount is not currently directly borne by us, we believe it reflects the portion of the compensation paid by Quantum Resources Management that is allocable to the services our named executive officers perform for us.  The portion of the salary paid to Cedric Burgher has not been allocated based on the applicable production percentage but has been prorated for the period beginning on December 22, 2010, the date of the closing of our initial public offering, and ending on December 31, 2010.
 
 (2)
Reflects the portion of the cash bonuses paid by Quantum Resources Management to each of our named executive officersthat is reimbursable by our general partner under the services agreement after December 31, 2012 (allocated based on the applicable production percentage, which was 29.96% for 2010),prorated for the period beginning on December 22, 2010, the date of the closing of our initial public offering, and ending on December 31, 2010.  Although these bonuses were paid in early 2011, they relate to services performed in 2010.In addition, while this amount is not currently directly borne by us, we believe it reflects the portion of the compensation paid by Quantum Resources Management that is allocable to the services our named executive officers perform for us. The portion of the bonus paid to Cedric Burgher has not been allocated based on the applicable production percentage but has been prorated for the period beginning on December 22, 2010, the date of the closing of our initial public offering, and ending on December 31, 2010.
 
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  (3)
Reflects the aggregate fair value of restricted unit awards granted under the LTIP on the grant date based on the closing price of our common units on December 22, 2010, $20.03 per common unit.  See Note 12 to our consolidated financial statements for fiscal 2010 for additional detail regarding assumptions underlying the value of these equity awards.
  (4)
Messrs. Burgher, Roden and Selzer were each granted $200,300 of restricted unit awards under the LTIP. upon the closing of our initial public offering. These restricted units vest in equal one-third increments over a 36-month period, provided that the named executive officer has continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the date of grant through each applicable vesting date.
 
 (5)
Because Mr. Burgher will devote all of his time to our business once he ceases to serve as the Chief Financial Officer of the Fund, he also received an additional grant of 75,000 restricted units in connection with the closing of our initial public offering as an employment inducement award.  These restricted units vest in equal one-fifth increments over a 60-month period, provided that Mr. Burgher has continuously provided services to us, our general partner or any of our respective affiliates, without interruption, from the date of grant through each applicable vesting date.
 
 (6)
Reflects the portion of the 401(k) matching contributions made on behalf of our named executive officers that is reimbursable by our general partner under the services agreement after December 31, 2012 (allocated based on the applicable production percentages described above under “—Compensation Discussion and Analysis”), prorated for the period beginning on December 22, 2010, the date of the closing of our initial public offering, and ending on December 31, 2010.  While this amount is not currently directly borne by us we believe it reflects the portion of the compensation paid by Quantum Resources Management that is allocable to the services our named executive officers perform for us.
  Grants of Plan-Based Awards for Fiscal 2010
 
 The following table sets forth certain information with respect to grants of restricted units to our named officers in fiscal 2010.
  Number of Shares


Grant Date Fair Value ofName

Grant Date

of Stock or Units(1)


Stock and Option Awards(2)Alan L. Smith

-


-


$
-John H. Campbell, Jr.

-


-


$
-Cedric W. Burgher

12/22/2010


10,000


$
200,300Cedric W. Burgher

12/22/2010


75,000


$
1,502,250Gregory S. Roden

12/22/2010


10,000


$
200,300Howard K. Selzer

12/22/2010


10,000


$
200,300
  (1)
Reflects the grant of restricted units under the LTIP made to our named executive officers in connection with our initial public offering.
 
 (2)
Reflects the aggregate fair value of restricted unit awards granted under the LTIP based on the closing price of our common units on the December 22, 2010, $20.03 per common unit. See Note 12 to our consolidated financial statements for fiscal 2010 for additional detail regarding assumptions underlying the value of these equity awards.
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  Outstanding Equity Awards at December 31, 2010
 
 The following table sets forth certain information with respect to outstanding equity awards at December 31, 2010.
  Name

Number of Shares or Units of Stock That Have Not Vested


Market Value of Shares or Units of Stock That Have Not Vested(2)Alan L. Smith


-


$
-John H. Campbell, Jr.


-


$
-Cedric W. Burgher (1), (3)


85,000


$
1,710,200Gregory S. Roden (1)


10,000


$
201,200Howard K. Selzer (1)


10,000


$
201,200
 
 (1)
3,333 units of each 10,000 unit grant will vest on December 22, 2011, 3,333 units will vest on December 22, 2012, and 3,334 units will vest on December 31, 2013, subject to continued service.
 
 (2)
This column represents the closing price of our common units on December 31, 2010, which was $20.12, multiplied by the number of restricted units outstanding.
  (3)
Mr. Burgher received, in addition to his 10,000 unit grant, a 75,000 unit grant, 15,000 units of which will vest on the first through fifth anniversaries of December 22, 2010, subject to his continued service.
 
 Option Exercises and Stock Vested
 
 No equity-based awards held by our named executive officers vested or were exercised during fiscal year 2010.
 
 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.
 
 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
 
 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.
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 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, 2010 and using our closing stock price on that date of $20.12. 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

$
-


$
-John H. Campbell, Jr.

$
-


$
-Cedric W. Burgher

$
1,710,200


$
1,710,200Gregory S. Roden

$
201,200


$
201,200Howard K. Selzer

$
201,200


$
201,200
  (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, 2010, $20.12, multiplied by the number of restricted units that would vest upon the occurrence of the event indicated.
 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.  Each director who is not an officer or employee of our general partner or its affiliates receives compensation for attending meetings of the board of directors, as well as committee meetings.  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, in addition to reimbursing our general partner for payments to Quantum Resources Management under the services agreement.  The portion of any quarterly management incentive fee paid to Mr. Wolf will not be an expense reimbursed by our general partner or us under the series agreement.
 
 The directors of the general partner received no direct compensation from us or our general partner during fiscal 2010.  In fiscal 2011, our general partner will pay each of Messrs. Powell and Thorington $75,000 in cash and 3,750 units under the LTIP in annual compensation for their services as directors of our general partner. In addition, each non-employee director is reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees.  Each director is fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.
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  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.
 
 ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
 
 As of December 31, 2010, the following table sets forth the beneficial ownership of our common and subordinated units that are owned by:
 
 ·
Each person who then will beneficially own 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)


Percentage of

Common Units

to be Beneficially

Owned(3)


Subordinated

Units to be

Beneficially

Owned


Percentage of

Subordinated

Units to be

Beneficially Owned


Percentage of Total

Common and

Subordinated Units to be

Beneficially Owned(3)The Fund


11,297,737



43.0
%


7,145,866



100.0
%


55.1
%Donald D. Wolf(7)


-



0.0
%


-



0.0
%


0.0
%Alan L. Smith (7), (8)


11,347,737



43.2
%


7,145,866



100.0
%


55.2
%John H. Campbell, Jr.(7), (8)


11,297,737



43.0
%


7,145,866



100.0
%


55.1
%Cedric W. Burgher


90,000



0.1
%


-



0.0
%


0.1
%Gregory S. Roden(4)


10,000



0.1
%


-



0.0
%


0.1
%Howard K. Selzer (5)


10,400



0.1
%


-



0.0
%


0.1
%Toby R. Neugebauer (7), (8)


11,297,737



43.0
%


7,145,866



100.0
%


55.1
%S. Wil VanLoh (7), (8)


11,297,737



43.0
%


7,145,866



100.0
%


55.1
%Donald E. Powell


-



0.0
%


-



0.0
%


0.0
%Stephen A. Thorington (6)


20,000



0.1
%


-



0.0
%


0.1
%All named executiveofficers, and directors as a group (10 persons)


11,297,737



43.0
%


7,145,866



100.0
%


55.1
%
 (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.
 
 (3)
Includes 75,000 units issued to Mr. Burgher under the LTIP program upon the consummation of IPO, 10,000 units issued to Mr. Burgher under the LTIP program as part of his 2010 compensation and 5,000 units purchased by Mr. Burgher as part of the directed unit program.
 
 (4)
Includes 10,000 common units issued to Mr. Roden as part of his 2010 compensation.
 
 (5)
Includes 10,000 common units issued to Mr. Selzer as part of his 2010 compensation and 400 units purchased by Mr. Selzer as part of the directed unit program.
 
 (6)
Includes 20,000 common units acquired by Mr. Thorington under the directed unit program.
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 (7)
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, LLC (“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 10,329,092 common units and 6,533,194 subordinated units;
 ·
QRB owns 186,283 common units and 117,825 subordinated units;
 ·
QRC owns 330,670 common units and 209,150 subordinated units;
 ·
QAB owns 3,802 common units and 2,405 subordinated units;
 ·
QAC owns 6,748 common units and 4,268 subordinated units;
 ·
Black Diamond owns 441,142 common units and 279,024 subordinated units.
 ·
Three directors of our general partner, Messrs. Wolf, Neugebauer and VanLoh, and two directors and executive officers of our general partner, Messrs. Smith and Campbell, are also members of the board of directors of HoldCo GP, and as such, are entitled to vote on decisions to vote, or to direct to vote and to dispose, or to direct the disposition of, the common units and subordinated units held by the Fund but cannot individually or together control the outcome of such decisions. HoldCo GP and Messrs. Wolf, Neugebauer, VanLoh, Smith and Campbell disclaim beneficial ownership of the common units and subordinated units held by the Fund.
  (8)
Our general partner, QRE GP, LLC, is owned 50% by an entity controlled by Mr. Neugebauer and Mr. VanLoh and 50% by an entity controlled by Mr. Smith and Mr. Campbell. As indirect owners of our general partner, Messrs. Neugebauer, VanLoh, Smith and Campbell share in distributions made by us with respect to units held by our general partner in proportion to their respective ownership interests. Messrs. Neugebauer, VanLoh, Smith and Campbell, by virtue of their ownership interest in our general partner, may be deemed to beneficially own the units held by our general partner.
 
 Securities Authorized for Issuance under Equity Compensation Plans
 
 The following table summarizes information about our equity compensation plans as of December 31, 2010:
  Plan Category

Outstanding

restricted units as of

December 31, 2010

Weighted-average exercise

price of outstanding options,

warrants and rights

Number of units remaining available

for future issuance under equity

compensation plans as of

December 31, 2010Equity compensation plans notapproved by unitholders (1)Long-term incentive plan

148,150

n/a

1,651,850
  (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 "Item 11. Executive Compensation" above.
  ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
 Contracts with QRE GP, LLC and Its Affiliates
 
 Our general partner has entered into agreements with the Fund and its affiliates.  The following is a description of those agreements.
 
 Ownership in Our General Partner by the Management of the Fund
 
 As of December 31, 2010, entities controlled by affiliates of the Fund owned the QRE GP partner and a 55.1% limited partner interest in the Partnership. In addition, the general partner owns a 0.1% general partner interest in the Partnership, represented by 35,729 general partner units.
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 Table Of Contents
  Contribution Agreement
  On December 22, 2010, in connection with the closing of the Offering, the following transactions, among others, occurred pursuant to the Contribution, Conveyance and Assumption Agreement by and among the Partnership, the General Partner, OLLC and the Fund (the “Contribution Agreement”):
  ·
the General Partner agreed to contribute capital to the Partnership to maintain its 0.1% general partner interest in the Partnership, represented by 35,729 general partner units;
 
 ·
the Fund contributed certain assets to the Partnership in exchange for, among other things, (i) 7,145,866 Subordinated Units, (ii) 11,297,737 Common Units, (iii) a distribution of $300 million and (iv) the Partnership’s and OLLC’s assumption of  $200 million of the Fund’s existing indebtedness;
 
 Services Agreement
  On December 22, 2010, in connection with the closing of the Offering, 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 the Partnership’s business. Under the Services Agreement, from the closing of the Offering through December 31, 2012, Quantum Resources Management will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by the Partnership during the preceding quarter, calculated prior to the payment of the fee. After December 31, 2012, in lieu of the quarterly administrative services fee, the general partner will reimburse Quantum Resources Management, on a quarterly basis, for the allocable expenses Quantum Resources Management incurs in its performance under the Services Agreement and the Partnership will reimburse the general partner for such payments it makes to Quantum Resources Management. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated by Quantum Resources Management to its affiliates. During the period from the closing of the Offering through December 31, 2010, we incurred $0.1 million for the administrative services fee under the Services Agreement.
  Omnibus Agreement
  On December 22, 2010, in connection with the closing of the Offering, 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 the Partnership 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 the Partnership to participate in at least 25% of any acquisition opportunity to the extent that it invests any of the remaining $150 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. In addition to opportunities to purchase proved reserves from, and to participate in future acquisition opportunities with, the Fund Entities, if QA Global or its affiliates establish another fund to acquire oil and natural gas properties within two years of the closing of the Offering, QA Global will cause such fund to provide the Partnership with a similar right to participate in such fund’s acquisition opportunities. These contractual obligations will remain in effect for five years after the date of the Omnibus Agreement.
  The Omnibus Agreement provides that the Fund Entities will indemnify the Partnership in connection with those assets contributed to the Partnership at the closing of the Offering against: (i) title defects, subject to a $75,000 per claim de minimus exception, for amounts in excess of a $4.0 million threshold and (ii) income taxes attributable to pre-closing operations as of the closing date of the Offering. The Fund indemnification obligation will (i) survive for one year after the closing of the Offering with respect to title and (ii) terminate upon the expiration of the applicable statute of limitations with respect to income taxes. The Partnership will indemnify the Fund Entities against certain potential environmental claims, losses and expenses associated with the operation of the Partnership’s business that arise in connection with those assets contributed to the Partnership at the closing of the Offering after the consummation of the Offering.
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 Table Of Contents
 
 Long–Term Incentive Awards / Plan
  On December 22, 2010, in connection with the closing of the Offering, the Board of Directors of the general partner adopted the QRE GP, LLC Long Term Incentive Plan (the “Plan”) 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 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 long-term incentive plan is to provide additional incentive compensation to employees providing services to us and to align the economic interests of such employees with the interests of our unitholders. The Plan 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, 2010, 148,150 restricted unit awards totaling $2.8 million were granted under the Plan.
 
 Distributions of available cash to our general partner and affiliates
  We will generally make cash distributions to our unitholders and general partner pro rata, including our general partner and our affiliates. As of January 3, 2011, our general partner and its affiliates held 11,297,737 common units, all of the subordinated units and 35,729 general partner units. No cash distributions were made as of December 31, 2010.
 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 “Item 10. Directors, Executive Officers and Corporate Governance—Committees of the Board of Directors and Independence Determination.”
 
 ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES
 
 The audit committee of QRE GP, LLC selected PricewaterhouseCoopers LLP, an independent registered public accounting firm, to audit our consolidated financial statements for the year ended December 31, 2010.  The auditcommittee’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, 2010 were approved by the audit committee.
 
 Fees paid to PricewaterhouseCoopers LLP ("PwC") are as follows:
  Partnership


Predecessor2010(3)


2010(3)


2009Audit Fees(1)

$
-


$
1,492


$
515Audit - related fees


-



-



-Tax fees


-



-



-All other fees (2)


-



3



-Total fees paid to PwC

$
-


$
1,495


$
515
  (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)
Other fees relate to accounting software fees.
 (3)
The Predecessor has borne all IPO audit fees of the Partnership. These fees have been included in the Predecessor's audit fees for 2010 above. During the ten day Post-IPO period from December 22, 2010 to December 31, 2010, no audit fees were incurred by the Partnership.
 97
 Table Of Contents
  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 financials statements or notes thereto.
 
 (a)(3) Exhibits
  Exhibit

Number


Description3.1

—
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

—
Agreement of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.2 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).3.3

—
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).3.4

—
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).3.5

—
Limited Liability  Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.5 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).3.6

—
First Amendment to Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.6 of the Partnership’s Registration Statement on Form S-1/A (File No. 333-169664) filed on November 26, 2010).3.7

—
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).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

—
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).10.6
+
—
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).21.1
*
—
List of Subsidiaries of QR Energy, LP23.1
*
—
Consent of PricewaterhouseCoopers LLP23.2
*
—
Consent of KPMG LLP23.3
*
—
Consent of Miller and Lents, Ltd.31.1
*
—
Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 193431.2
*
—
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 193432.1
**
—
Certification of the 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 the 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 Miller and Lents, Ltd.
 ______________
 * Filed as an exhibit to this Annual Report on Form 10-K.
 ** Furnished as an exhibit to this Annual Report on Form 10-K.
 + Management contracts or compensatory plans or arrangements
 
 98
 Table Of Contents
  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)By: QRE GP, LLC, its general partnerDate: May 4, 2011
By:  /s/ Cedric W. BurgherCedric W. BurgherChief 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 May 4, 2011.
 
 Signature

Title  (Position with QRE GP, LLC)

Date/s/ Alan L Smith

Chief Executive Officer and Director

May 4, 2011Alan L. Smith

(Principal Executive Officer)/s/ John H. Campbell, Jr.

President, Chief Operating Officer and Director

May 4, 2011John H. Campbell, Jr./s/ Cedric W. Burgher

Chief Financial Officer

May 4, 2011Cedric W. Burgher

(Principal Financial Officer)/s/ Gregory S. Roden

Vice President, Secretary and General Counsel

May 4, 2011Gregory S. Roden/s/ Howard K. Selzer

Chief Accounting Officer

May 4, 2011Howard K. Selzer

(Principal Accounting Officer)/s/ Toby R. Neugebauer

Director

May 4, 2011Toby R. Neugebauer/s/ Donald E. Powell

Director

May 4, 2011Donald E. Powell/s/ Stephen A. Thorington

Director

May 4, 2011Stephen A. Thorington/s/ S. Wil VanLoh, Jr.

Director

May 4, 2011S. Wil VanLoh, Jr.
 s/ Donald D. Wolf

Chairman of the Board

May 4, 2011Donald D. Wolf
  99
 Table Of Contents
  INDEX TO FINANCIAL STATEMENTS
  QR ENERGY, LP AUDITED CONSOLIDATED FINANCIAL STATEMENTS
 Reports of Independent Registered Public Accounting Firms
F-2Consolidated Balance Sheets as of December 31, 2010 and 2009
F-5Consolidated Statements of Operations for the Periods from December 22, 2010 to December 31, 2010, from January 1, 2010 to December 21, 2010 and the Years ended December 31, 2009 and 2008
F-6Consolidated Statement of Changes in Owners' Equity for the Period from December 22, 2010 to December 31, 2010
F-7Consolidated Statement of Changes in Owners' Equity for the Period from January 1, 2010 to December 21, 2010 and the Years ended December 31, 2009 and 2008
F-8Consolidated Statements of Cash Flows for the Periods from December 22, 2010 to December 31, 2010, from January 1, 2010 to December 21, 2010 and the Years ended December 31, 2009 and 2008
F-9Notes to Consolidated Financial Statements
F-10
  F-1
 Table Of Contents
 
 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
  To the Board of Directors of QRE GP, LLC
  And Unitholders of QR Energy, LP
  In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, changes in owners' equity and cash flows present fairly, in all material respects, the financial position of QR Energy, LP and its subsidiary (the "Partnership") at December 31, 2010 and the results of their operations and their cash flows for the period from December 22, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
  PricewaterhouseCoopers LLP
  Houston, Texas
  May 4, 2011
  F-2
 Table Of Contents
 
 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
  To the Board of Directors of QRE GP, LLC
  And Unitholders of QR Energy, LP
  In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, changes in owners' equity and cash flows present fairly, in all material respects, the financial position of QA Holdings, LP and its subsidiaries (the "Predecessor") at December 31, 2009 and the results of their operations and their cash flows for the year ended December 31, 2009 and for the period from January 1, 2010 to December 21, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
 As discussed in Note 2 to the consolidated financial statements, effective December 31, 2009, the Predecessor changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
 
 PricewaterhouseCoopers LLP
  Houston, Texas
  May 4, 2011
  F-3
 Table Of Contents
 
 Report of Independent Registered Public Accounting Firm
 
 The Board of Directors of QRE GP, LLC
 And Unitholders of QR Energy, LP:
 
 We have audited the accompanying consolidated statements of operations, changes in owners’ equity and cash flows of QA Holdings, LP (the Predecessor) for the year ended December 31, 2008. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
 
 We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
 
 In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of their operations and cash flows of QA Holdings, LP (the Predecessor) for the year ended December 31, 2008 in conformity with U.S. generally accepted accounting principles.
 
 /s/ KPMG LLP
 Denver, Colorado
 April 30, 2009
 F-4
 Table Of Contents
  QR ENERGY, LP
 CONSOLIDATED BALANCE SHEETS (In thousands, except unit amounts)
 
 Partnership


PredecessorDecember 31,


December 31,2010


2009ASSETSCurrent assets:Cash and cash equivalents

$
2,195


$
17,156Accounts receivable:Trade and other, net of allowance for doubtful accounts


-



2,796Oil and gas sales


3,014



10,573Due from general partner


715



-Derivative instruments


9,027



7,783Prepaid and other current assets


1,264



2,533Total current assets


16,215



40,841Noncurrent assets:Oil and gas properties, using the full cost method of accounting


444,710



709,552Gas processing equipment


-



4,386Furniture, equipment, and other


-



3,959Less accumulated depreciation, depletion, amortization and impairment


(913
)


(592,254
)Total property and equipment, net


443,797



125,643Investment in Ute Energy, LLC


-



41,597Derivative instruments


9,020



-Deferred taxes


341



-Other long-term assets (See Note 6)


2,645



18,689Total noncurrent assets


455,803



185,929Total assets

$
472,018


$
226,770LIABILITIES AND OWNERS' EQUITYCurrent liabilities:Accounts payable

$
-


$
1,845Oil and gas sales payable


-



8,578Payable to affiliates


442



-Current portion of asset retirement obligations


1,848



2,250Derivative instruments


7,045



14,484Accrued and other liabilities


3,806



13,758Total current liabilities


13,141



40,915Noncurrent liabilities:Long-term debt


225,000



86,450Derivative instruments


19,832



52,998Asset retirement obligations


16,440



32,994Other long term liabilities


-



101Total noncurrent liabilities


261,272



172,543Commitments and contingencies (See Note 9)Owners' equity:Predecessor partners' capital


-



(1,421
)General partner (35,729 units issued and outstandingas of December 31,2010)


708



-Public common unitholders (15,000,000 units issued andoutstanding as of December 31, 2010)


276,723



-Affiliated common unitholders (11,297,737 units issued andoutstanding as of December 31, 2010)


(48,898
)


-Subordinated unitholders (7,145,866 units issued and outstandingas of December 31, 2010)


(30,928
)


-Total partners' capital


197,605



(1,421
)Predecessor noncontrolling interest


-



14,733Total owners' equity


197,605



13,312Total liabilities and owners' equity

$
472,018


$
226,770
 
 See accompanying notes to the consolidated financial statements
  F-5
 Table Of Contents
   QR ENERGY, LP CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts)
 Partnership


PredecessorDecember 22 to

December 31,

2010


January 1 to

December 21,

2010


Year Ended

December 31,

2009


Year Ended

December 31,

2008Revenues:Oil and natural gas sales

$
3,014


$
244,572


$
69,193


$
248,529Processing and other


-



8,814



3,608



18,800Resale of natural gas


-



-



-



13,741Total revenues


3,014



253,386



72,801



281,070Operating Expenses:Production expenses


939



108,408



44,841



117,219Purchases of natural gas


-



-



-



13,960Impairment of oil and gas properties


-



-



28,338



451,440Depreciation, depletion and amortization


913



66,482



16,993



49,309Accretion of asset retirement obligations


25



3,674



3,585



3,004Management fees


-



10,486



12,018



12,018Acquisition evaluation costs


-



1,192



582



216Offering costs


-



5,148



-



-General and administrative


280



25,477



18,697



14,487Bargain purchase gain


-



-



(1,200
)


-Other expense


-



224



-



-Total operating expenses


2,157



221,091



123,854



661,653Operating income (loss)


857



32,295



(51,053
)


(380,583
)Other income (expense):Equity in earnings of Ute Energy, LLC (See Note 16)


-



3,782



2,675



(3,010
)Dividends on investment in marketable equity securities


-



-



233



579Gain (loss) on investment in marketable equity securities


-



-



394



(7,608
)Gain (loss) on commodity derivative contracts


(7,694
)


13,577



(63,120
)


134,655Gain on equity share issuance (See Note 16)


-



4,064



-



-Interest expense, net


(304
)


(22,179
)


(3,716
)


(12,417
)Other income (expense)


-



482



(645
)


-Total other income (expense), net


(7,998
)


(274
)


(64,179
)


112,199Income (loss) before income taxes


(7,141
)


32,021



(115,232
)


(268,384
)Income tax benefit (expense), net


42



(108
)


(182
)


(149
)Net income (loss)


(7,099
)


31,913



(115,414
)


(268,533
)Net income (loss) attributable to noncontrolling interest


-



30,101



(107,528
)


(258,541
)Net income (loss) attributable to controlling interest

$
(7,099
)

$
1,812


$
(7,886
)

$
(9,992
)General partner's interest in net loss

$
(7
)Limited partner's interest in net loss

$
(7,092
)Net loss per limited partner unit (basic and diluted)

$
(0.21
)Weighted average number of limited partner unitsoutstanding (basic and diluted)


33,444
 See accompanying notes to the consolidated financial statements
  F-6
 Table Of Contents
  QR ENERGY, LP CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (In thousands)
  Limited PartnersGeneral


Public


AffiliatedPartner


Common


Common


Subordinated


TotalBalance - December 22, 2010

$
-


$
-


$
-


$
-


$
-Book value of net assets contributedby the Predecessor (See Note 1)


-



-



137,051



86,685



223,736Initial public offering (See Note 1)


-



279,750



-



-



279,750Deferred tax benefit as a result of IPO (See Note 2)


-



134



101



64



299Contributions from general partner


715



-



-



-



715Other contributions (See Note 15)


-



-



113



71



184Amortization of equity awards


-



20



-



-



20Distribution to the Fund (See Note 1)


-



-



(183,767
)


(116,233
)


(300,000
)Net loss


(7
)


(3,181
)


(2,396
)


(1,515
)


(7,099
)Balance, December 31, 2010

$
708


$
276,723


$
(48,898
)

$
(30,928
)

$
197,605
 See accompanying notes to the consolidated financial statements
  F-7
 Table Of Contents
  PREDECESSOR - QA HOLDINGS, LP CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (In thousands)
 General

Partner


Limited

Partners


Total

Partners'

Capital


Non-controlling

Interest


Total

EquityBalance - December 31, 2007

$
50


$
5,053


$
5,103


$
235,201


$
240,304Contributions by partners


114



11,272



11,386



175,346



186,732Distribution to partners


(5
)


(535
)


(540
)


(18,028
)


(18,568
)Net loss


(100
)


(9,892
)


(9,992
)


(258,541
)


(268,533
)Balance - December 31, 2008


59



5,898



5,957



133,978



139,935Contributions by partners


14



1,427



1,441



14,550



15,991Distribution to partners


(9
)


(924
)


(933
)


(26,267
)


(27,200
)Net loss


(79
)


(7,807
)


(7,886
)


(107,528
)


(115,414
)Balance - December 31, 2009


(15
)


(1,406
)


(1,421
)


14,733



13,312Contributions by partners


141



13,921



14,062



460,802



474,864Distribution to partners


(9
)


(891
)


(900
)


(29,100
)


(30,000
)Amortization of equity awards (See Note 12)


16



1,601



1,617



-



1,617Net income


18



1,794



1,812



30,101



31,913Balance - December 21, 2010

$
151


$
15,019


$
15,170


$
476,536


$
491,706
  See accompanying notes to the consolidated financial statements
  F-8
 Table Of Contents
  QR ENERGY, LP
 CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
 Partnership


PredecessorDecember 22 to December 31,


January 1 to December 21,

Year Ended December 31,2010


2010

2009

2008Cash flows from operating activities:Net Income (loss)

$
(7,099
)

$
31,913

$
(115,414
)
$
(268,533
)Adjustments to reconcile net income (loss) to net cash provided by (used in)operating activities:Depreciation, depletion and amortization


913



66,482


16,993


49,309Accretion of asset retirement obligations


25



3,674


3,585


3,004Amortization of deferred financing costs


14



2,681


627


556Amortization of equity awards


20



3,470


-


-General and administrative expense contributed by the Fund


184



-


-


-Impairment of oil and gas properties


-



-


28,338


451,440Purchase of derivative contracts


-



-


-


(2,694
)Amortization of costs of derivative contracts


-



-


1,219


7,981Unrealized (gains) losses on derivative contracts (See Note 5)


7,405



(5,598
)

108,164


(167,389
)Unrealized (gains) losses on investment in marketable equity securities


-



-


(5,640
)

5,640Realized losses on investment in marketable equity securities


-



-


5,246


1,968Deferred income tax benefit


(43
)


-


-


-(Gain) loss on disposal of furniture, fixtures and equipment


-



(482
)

723


-Bargain purchase gain


-



-


(1,200
)

-Equity in earnings of Ute Energy, LLC


-



(3,782
)

(2,675
)

3,010Gain on equity share issuance


-



(4,064
)

-


-Changes in operating assets and liabilities:Accounts receivable and other assets


(4,278
)


(39,727
)

15,052


(3,768
)Accounts payable and other liabilities


2,576



41,378


9,889


(5,242
)Net cash provided by (used in) operating activities


(283
)


95,945


64,907


75,282Cash flows from investing activities:Additions to oil and gas properties


-



(56,133
)

(31,278
)

(90,125
)Acquisition of oil and gas properties


-



(891,870
)

(43,300
)

(391
)Additions to furniture, equipment and other


-



(1,934
)

(1,456
)

(943
)Proceeds from sale of gas processing assets


-



890


-


-Proceeds from sale of other assets


-



170


-


-Increase in property reclamation deposit


-



-


(19
)

(254
)Investment in Ute Energy, LLC


-



-


(1,925
)

(27,000
)Investment in marketable equity securities


-



-


-


(15,291
)Proceeds from sales of marketable equity securities


-



-


6,233


1,843Property acquisition deposit


-



(8,000
)

-


-Increase in other assets


-



-


-


(5,000
)Proceeds from sale of properties


-



-


16,287


-Net cash used in investing activities


-



(956,877
)

(55,458
)

(137,161
)Cash flows from financing activities:Net proceeds from initial public offering (See Note 1)


279,750



-


-


-Distributions to the Fund (See Note 1)


(300,000
)


-


-


-Intercompany financing from the Fund (See Note 15)


387



-


-


-Contributions by partners and non-controlling interest owners


-



474,864


15,991


186,731Distributions to partners and non-controlling interest owners


-



(30,000
)

(27,019
)

(18,568
)Proceeds from bank borrowings (See Note 8)


225,000



584,383


33,000


25,000Repayment of debt assumed from the Fund (See Note 8)


(200,000
)


-


-


-Repayments on bank borrowings


-



(113,752
)

(35,300
)

(162,525
)Deferred financing costs


(2,659
)


(12,047
)

-


(398
)Net cash provided by (used in) financing activities


2,478



903,448


(13,328
)

30,240Increase (decrease) in cash and cash equivalents


2,195



42,516


(3,879
)

(31,639
)Cash and cash equivalents at beginning of period


-



17,156


21,035


52,674Cash and cash equivalents at end of period

$
2,195


$
59,672

$
17,156

$
21,035
 
 See accompanying notes to the consolidated financial statements
  F-9
 Table Of Contents
 
 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 receive certain of the assets of QA Holdings, LP (the “Predecessor”). Our general partner is QRE GP, LLC (“QRE GP”). We operate the acquired assets through our wholly owned operating company QRE Operating, LLC (“OLLC”).
 
 The Predecessor is a Delaware limited partnership, which commenced operations on April 1, 2006 for the primary purpose of acquiring, owning, enhancing and producing oil and gas properties through its subsidiaries. The Predecessor holds general partner interests in a collection of limited partnerships. Certain of the Predecessor’s subsidiary limited partnerships, (collectively known as the “Fund”) comprise 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. The Fund is managed by Quantum Resources Management, LLC (“QRM”), a full service management company formed to manage the oil and natural gas interests of the Predecessor. The general partner of the Predecessor and the individual entities included in the Fund is QA Global GP, LLC (“QA Global”).
 
 On December 22, 2010 (the “Closing Date”), we completed our initial public offering (“IPO”) of 15,000,000 common units representing limited partner interests in the Partnership at $20.00 per common unit, or $18.70 per unit after payment of the underwriting discount. Total net proceeds from the sale of the common units in the IPO were $279.8 million ($300 million less $19.5 million underwriters’ discount and $0.7 million structuring fee). IPO costs totaling $5.1 million were borne entirely by the Fund and are included in offering costs in the Predecessor’s consolidated statement of operations for the period January 1 to December 21, 2010.
 
 On the Closing Date, we also entered into the following agreements and transactions with the Fund:
 
 Contribution Agreement and Concurrent Transactions
 
 ·
A Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) was executed on the Closing Date by and among the Fund, the Partnership and QRE GP with net assets contributed by the Fund to the Partnership using carryover book value of the Fund as the transaction is a transfer of assets between entities under common control as follows:
 
 Oil and gas properties, net(1)

$
444,671Natural gas imbalance (2)


(1,247
)Long-term debt (3)


(200,000
)Derivative instrument liability, net(4)


(1,425
)Asset retirement obligation (5)


(18,263
)Net assets

$
223,736
  (1)
Book value of certain oil and gas properties in the Permian Basin and the Ark-La-Tex, Mid-Continent and Gulf Coast areas as well as an overriding royalty interest in the Gulf Coast area.
 (2)
Natural gas imbalances contributed by the Fund representing overproduced positions for which a liability was incurred as of the Closing Date.
 (3)
The Partnership assumed $200 million of the Fund’s existing long-term debt.
 (4)
Novation of derivative instruments from the Fund to the Partnership was concurrent with the IPO but not part of the Contribution Agreement which were transferred at fair value on the Closing Date. The fair value is reflected in the Predecessor’s book value by the means of non-recurring valuation measurements as of the date of transfer. See Note 4.
 F-10
 Table Of Contents
  (5)
Asset retirement obligations specifically identified with relation to oil and gas properties contributed. Liability balance represents the historical book value as of the Closing Date.
 ·
In exchange for the net assets above, the Fund received 11,297,737 common and 7,145,866 subordinated limited partner units.
 ·
The Fund also received a $300 million cash distribution.
 ·
QRE GP made a capital contribution of $ 0.7 million in exchange for 35,729 QRE GP units. The contribution was received in January 2011.
 
 As a result of these transactions our ownership structure comprised a 0.1% general partnership interest held by QRE GP, 55.1% in limited partner interests held by the Fund and 44.8% in limited partner interests held by the public unitholders.
 
 Services Agreement
 
 We entered into a Services Agreement (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. Under the Services Agreement, from the closing of the IPO through December 31, 2012, QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. After the term of the Services Agreement, in lieu of the quarterly administrative services fee, QRE GP will reimburse QRM, on a quarterly basis, for the allocable expenses QRM incurs in its performance under the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM.
 
 Omnibus Agreement
 
 We entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among QRE GP, OLLC, the Fund, the Predecessor and QA Global. The Omnibus Agreement governs the following types of potential transactions:
 
 ·
The Fund agrees to provide us, for at least five years from the Closing Date, the first opportunity to purchase certain oil and gas assets it may offer for sale which consist of at least 70% proved developed producing reserves.
 ·
The Fund agrees to allow us the first option to participate in certain of its acquisition opportunities so long as 70% of the allocated value of the acquisition is attributable to proved developed producing reserves for a period of five years from the Closing Date.
 ·
Should QA Global or any of its affiliates close any new investment fund within two years from the Closing Date, the Omnibus Agreement shall be amended to include those entities as parties to the terms in the first two points above.
 
 For additional discussion of the agreements listed above see Note 15.
 
 NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
 Basis of Presentation
 
 The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2010 and the Predecessor’s consolidated financial position as of December 31, 2009. These financial statements also include the results of our operations, cash flows and changes in owners’ equity for the period of December 22 to December 31, 2010 and those of our Predecessor for the periods of January 1 to December 21, 2010 and years ended December 31, 2009 and 2008. These consolidated financial statements include our wholly owned subsidiary and all the wholly owned subsidiaries of our Predecessor.
  F-11
 Table Of Contents
 
 Our consolidated statement of operations and consolidated statement of cash flows reflect activity since the closing of our IPO. We had no activity from September 20, 2010 (inception) to December 21, 2010.
 
 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. Certain line items previously reported on the Predecessor’s consolidated balance sheet, statements of operations and statement of cash flows have been combined based on materiality as allowed under GAAP and Securities and Exchange Commission (“SEC”) rules for financial statements and related disclosures. Certain reclassifications have been made to the previous years to conform to the 2010 presentation. These reclassifications do not affect the totals for current assets, current liabilities, noncurrent assets, noncurrent liabilities, operating expenses, other income (expenses), net income or cash flows.
 
 Use of Estimates
 
 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;
 ·
Fair values of derivative instruments, and
 ·
Fair values of assets acquired and liabilities assumed from business combinations.
 ·
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. The majority of cash and cash equivalents are maintained with several major financial institutions 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, 2010 and 2009, the allowance for doubtful accounts was not material to us or the Predecessor.
  F-12
 Table Of Contents
 
 Property and Equipment
 
 Oil and Gas Properties. We account for our oil and gas exploration and development activities under the full cost method of accounting. Under this method, all costs associated with property exploration and development (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and direct overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities are capitalized. 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.
 
 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 gas properties. The ceiling test provides that capitalized costs less related accumulated depreciation, depletion and amortization may not exceed an amount equal to (1) the present value of future net revenue from estimated production of proved oil and gas reserves, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, discounted at 10% per annum; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any. If the net capitalized costs exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs.
 
 Prior to December 31, 2009, the ceiling calculation dictated that prices and costs in effect as of the last day of the quarter be held constant. The current 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 quarter are held constant. Under both of these methods, 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 was no write-down required by us as of December 31, 2010. No write-down was required by the Predecessor for any quarter subsequent to March 31, 2009 through the period ended December 21, 2010. 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.
 
 During 2009 and 2008, the Predecessor recognized impairments of oil and gas properties of $28.3 million and $451.4 million. The adjusted prices used in the ceiling tests at the relevant quarter end dates are presented below:
 
 Commodity

Unit

March 31, 2009


December 31, 2008Oil

$/Bbl

$
48.39


$
41.00Natural Gas

$/MMbtu

$
3.58


$
5.71
 
 Depletion.The provision for depletion of proved oil and gas properties is calculated on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The Partnership and the Predecessor calculate depletion on a quarterly basis.
 
 Conveyance of Assets Between Entities Under Common Control
 
 Master limited partnerships (“MLPs”) from time to time enter into transactions whereby the MLP receives a transfer of certain assets from a sponsor (i.e. the Predecessor) with units issued to the sponsor and units sold to the public. We account for the assets received using the carryover book value of the Predecessor in accordance with guidance prescribed by the SEC.
 
 Oil and 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 engineering firm also adheres to the SEC definitions when preparing their reserve reports.
  F-13
 Table Of Contents
 
 Asset Retirement Obligations
 
 We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production 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 the liability, we report a gain or loss to the extent the actual costs differ from the recorded liability. See Note 7.
 
 Deferred Financing Costs
 
 Costs incurred in connection with the execution or modification of our credit facility are capitalized and charged to interest expense over the term of the revolver.
 
 Derivatives
 
 We monitor our exposure to various business risks, including commodity price 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.
 
 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, including realized and unrealized gains and losses, are reported as nonoperating income (loss) on the statements of operations in “gains (losses) on commodity derivatives.” Realized gains (losses) represent amounts related to the settlement of commodity derivatives which are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are noncash items. See Note 4 and Note 5.
 
 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. All of our derivatives as of December 31, 2010 are with parties who are also lenders under our credit facility. 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 5.
 
 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, 2010 or by the Predecessor as of December 31, 2009.
  F-14
 Table Of Contents
 
 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. Neither we nor our Predecessor have experienced any material credit losses on such sales in the past.
 
 In 2010, we evaluated our concentration of credit risk by evaluating customer receipts from our assets as if we owned the properties for the entire year. This pro forma analysis of our revenue process resulted in three customers accounting for 23%, 16% and 10% of our oil, natural gas and NGL revenues. This same process resulted in two customers accounting for 45% and 10% of the Predecessor’s oil, natural gas and NGL revenues.
 
 In 2009, three customers accounted for 24%, 12% and 10% of the Predecessor’s consolidated oil, natural gas and natural gas liquids revenues. In 2008, one customer accounted for 51% of the Predecessor’s consolidated oil, natural gas and natural gas liquids revenues.
 
 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.
 
 Revenue Recognition
 
 Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers. 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 13.
 
 General and Administrative Expenses
 
 Our potential sources of general and administrative expenses comprise the following types of expenses:
 
 ·
Direct general and administrative expenses incurred by QRM on our behalf (“Direct G&A”) and charged to us;
 ·
Administrative service fees 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”).
 
 During the term of the Services Agreement, our general and administrative expenses, for any quarter therein, will comprise Direct G&A, the administrative service fees and Allocated G&A in excess of the administrative service fees. We will not be required to reimburse QRM for Allocated G&A in excess of administrative service fees during the term of the Services Agreement. Therefore, these allocated expenses will be recorded as capital contributions from the Fund in our Consolidated Statement of Owners’ Equity. During the period from December 22, 2010 to December 31, 2010, these capital contributions totaled $0.2 million.
 
 Upon the termination of the Services Agreement, our general and administrative expenses for each quarter will comprise Direct G&A and Allocated G&A.
  F-15
 Table Of Contents
 
 Allocated G&A for any quarter is calculated using the ratio of our prior quarter production to the prior quarter production of all QRM affiliates for which QRM provides management services. For the period from December 22, 2010 to December 31, 2010, Allocated G&A was calculated using pro forma production volumes for the quarter ended December 31, 2010 as if the Fund had contributed the oil and gas properties on October 1, 2010. This ratio was applied to the total allocable indirect general and administrative expenses for the month of December 2010 and further reduced by the ratio of ten days to thirty-one days in order to estimate our Allocated G&A for the period from December 22, 2010 to December 31, 2010.
 
 Income Taxes
 
 We are treated as a partnership for income tax purposes. Generally, all of our taxable income and losses are reported on the income tax returns of the partners, and therefore, no provision for federal income taxes has been recorded in our accompanying consolidated financial statements. We are subject to Delaware franchise tax, however, such amounts are not significant.
 
 We are also subject to Texas Margin tax. As a result of the Fund’s contribution of oil and gas properties and derivative instruments to us, we recognized a deferred tax asset of $0.3 million based on the book to tax differences in the basis of those assets. We expect to realize the benefit of this asset in future periods through the generation of future taxable income and utilization of depletion deductions. For the period of December 22, 2010 through December 31, 2010, we recognized a deferred tax benefit for Texas Margin tax of less than $0.1 million.
 
 Net Income (Loss) per Limited Partner Unit
 
 Net income per limited partner unit is determined by dividing net income available to the limited partners, after deducting the general partner’s 0.1% interest in net income, by the weighted average number of limited partner units outstanding for the period from December 22, 2010 to December 31, 2010. Basic and diluted net income per unit are equivalent, as all subordinated units participate in distributions. See Note 11.
 
 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 approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. See Note 4.
 
 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.
 
 Unit-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 unit-based awards that contain service conditions, compensation cost is recorded using the straight-line method.
 
 As of December 31, 2010 we have granted awards to individuals who performed services for us in support of the completion of our IPO. All of the individuals receiving these units are employees of QRM performing services for us. We record these compensation costs as direct general and administrative expenses. See Note 12.
  F-16
 Table Of Contents
 
 Accounting Policies Applicable to the Predecessor
 
 Business Combinations
 
 The Predecessor has accounted for all business combinations using the purchase method, in accordance with GAAP. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. The Predecessor has not recognized any goodwill from any business combinations.
 
 Inventories
 
 Inventories, consisting primarily of tubular goods and other well equipment held for use in the development and production of natural gas and crude oil reserves, are carried at the lower of cost or market, on a first-in first-out basis. Adjustments are made from time to time to recognize, as appropriate, any reductions in value.
 
 Unproved Properties
 
 Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether there is a probability of obtaining proved reserves in the future. When it is determined 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 is transferred into the amortization base to be included in depletion calculations. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geological data obtained relating to the properties. Where it is not practicable to assess properties individually as their costs are not individually significant, such properties are grouped for purposes of the periodic assessment.
  Management Fees
 
 The Predecessor pays an affiliated entity to provide management services for the operation and supervision of its limited partnerships.  During 2010, the Predecessor determined it had over paid management fees by $0.8 million, spread over the last four years since inception in 2006. This amount was repaid in 2010 and thus reduced operating expenses. After evaluating the quantitative and qualitative aspects of these out-of-period errors, the Predecessor concluded its previously issued financial statements were not materially misstated and the effect of recognizing these adjustments in the 2010 financial statements were not material to the 2010 results  of operations, financial position and cash flows.
 Equity Investment
  The Predecessor has an investment in an unconsolidated entity in which the Predecessor does not own a majority interest but does have significant influence over, and is accounted for under the equity method. Under the equity method of accounting, the Predecessor's share of net income (loss) from its equity affiliate is reflected as an increase (decrease) in its investment account in "Other noncurrent assets" and is also recorded as "Equity in earnings of Ute Energy, LLC" in "Other income (expenses)." Distributions from the equity affiliate are recorded as reductions of the Predecessor's investment and contributions to the equity affiliate are recorded as increases of the Predecessor's investment. The Predecessor reviews its equity method investment for potential impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in the value of the investment has occurred.  See Note 16 for further information.
 Employee Benefit Plan
 
 The Predecessor has a 401(k) savings plan available to all eligible employees. The Predecessor matches 100% of employee contributions up to a certain percentage of the employee’s salary. Matching contributions vest immediately. The following table summarizes the Predecessor’s matching percentages and contributions for the periods indicated.
 
 PredecessorJanuary 1 to

December 21,

2010


Year Ended

December 31,

2009


Year Ended

December 31,

2008(In millions, except percentages)Percentage of employee's salary


3%



6%



6%Matching contributions


0.3



0.6



0.7
 Valuation-based compensation
 
 The Predecessor has various forms of equity-based and liability-based compensation outstanding under its employee compensation plan. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period.  Awards classified as liabilities are revalued at each reporting period and changes in the fair value of the options are recognized as compensation expense over the vesting periods of the awards. See Note 12 for further information.
 Recent Accounting Pronouncements
 
 In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2010-03, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements (ASU 2010-06) requiring additional disclosures about fair value measurements including transfers in and out of Levels 1 and 2 and increased disclosure of different types of financial instruments. For the reconciliation of Level 3 fair value measurements, information about purchases, sales, issuances and settlements should be presented separately. This guidance is effective for annual and interim reporting periods beginning after December 15, 2009 for most of the new disclosures and for periods beginning after December 15, 2010 for the new Level 3 disclosures. Our adoption did not have a material impact on our consolidated financial statements.
 
 On December 21, 2010, the FASB issued Accounting Standards Update No. 2010-29—Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations. The new guidance specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The update also expands the supplemental pro forma disclosures under Topic 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The update is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. This update was adopted by us on January 1, 2011 and will be considered if we enter into a business combination transaction.
  F-17
 Table Of Contents
 NOTE 3 —ACQUISITIONS
  Predecessor Acquisition of Denbury Properties
 
 On May 14, 2010, the Predecessor completed an acquisition to acquire certain oil and natural gas properties from Denbury Resources, Inc. (“Denbury”) for $893 million (the “Denbury Properties”). The Denbury Properties are located in the Permian Basin, Mid Continent and East Texas. Total proved reserves of the acquired properties were estimated to be 77 MMBoe as of May 14, 2010.
  The acquisition qualifies as a business combination, and as such, the Predecessor estimated the fair value of these properties as of the acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. The Predecessor used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 4.
 The Predecessor estimated that the fair value of the Denbury net assets acquired was approximately $918 million, with an associated ARO of $24.9 million, which the Predecessor considered to be representative of the price paid by a typical market participant. This measurement resulted in neither goodwill nor a bargain purchase gain. The acquisition related costs related to the Denbury acquisition were approximately $1.2 million and are recorded as acquisition evaluation costs for 2010.
 
 The following table summarizes the consideration paid by the Predecessor for the Denbury Properties and the final fair value of the assets acquired and liabilities assumed as of May 14, 2010.
 
 Consideration given to Denbury:Cash

$
888,785Preferential rights (Not yet paid at December 31, 2010)


4,058Total consideration

$
892,843Recognized amounts of identifiable assets acquired and liabilities assumed:Inventory (including hydrocarbons of $1,863)

$
6,384Proved developed properties (1)


788,829Proved undeveloped properties (1)


84,000Unproved properties (1)


43,000Suspended revenues payable


(4,521
)Asset retirement obligations


(24,849
)Total identifiable net assets

$
892,843
 (1)
The Predecessor used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 4.
 
 Summarized below are the consolidated results of operations for 2010 and 2009 for the Predecessor, on an unaudited basis, as if the acquisition had occurred on January 1 of each of the years presented. The unaudited pro forma financial information was derived from the Predecessor’s historical consolidated statement of operations and the statement of revenues and direct operating expenses for the Denbury Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Predecessor’s our expected future results of operations.
 
 2010


2009Actual


Pro Forma


Actual


Pro FormaRevenues

$
253,386


$
343,190


$
72,801


$
233,778Net Income (Loss)

$
31,913


$
98,455


$
(115,414
)

$
(94,962
)
 Predecessor Acquisition of Jay Field Properties
 
 The Predecessor signed and closed a purchase agreement on March 31, 2010 to acquire land within the Jay field from International Paper Company for $3.1 million.
  F-18
 Table Of Contents
  Predecessor Acquisition of Shongaloo Properties
 
 On January 28, 2009, the Predecessor completed an acquisition of 80 producing gas wells located in Arkansas and Louisiana (the “Shongaloo Properties”) for approximately $48.7 million from El Paso E&P Company, L.P. (“El Paso”). The acquisition was funded through cash calls to partners combined with borrowings under the Partnership’s credit facility. Total proved reserves of the acquired properties were estimated at 4.2 million barrels of oil equivalent at the date of acquisition.
 
 The following table summarizes the consideration paid for the Shongaloo Properties and the fair value of the assets acquired and liabilities assumed as of January 28, 2009.
 
 Consideration given to El PasoCash

$
48,700Recognized amounts of identifiable assets acquired and liabilities assumed:Proved developed properties (1)

$
51,600Asset retirement obligations


(1,700
)Bargain purchase


(1,200
)Total identifiable net assets

$
48,700
 (1)
The Predecessor used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 4.
 
 Summarized below are the consolidated results of operations for the years ended December 31, 2009 and 2008, on an unaudited pro forma basis, as if the acquisition had occurred on January 1 of each of the periods presented. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Predecessor and the statement of revenues and direct operating expenses for the Shongaloo Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Predecessor’s expected future results of operations.
 
 2009


2008Actual


Pro Forma


Actual


Pro FormaRevenues

$
72,801


$
73,713


$
281,070


$
307,510Net Loss

$
(115,414
)

$
(117,858
)

$
(268,533
)

$
(248,479
)
 Predecessor 2009 Acquisition Pro Forma
 Summarized below are the Predecessor’s consolidated results of operations for the year ended December 31, 2009, on an unaudited pro forma basis, as if the acquisitions of both the Denbury Properties and Shongaloo Properties had occurred on January 1, 2009. The unaudited pro forma financial information was derived from the Predecessor’s historical consolidated statement of operations and the statements of revenues and direct operating expenses for the Denbury Properties and Shongaloo Properties, which were derived from the historical accounting records of the sellers. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Predecessor’s expected future results of operations.
  2009Pro Forma AdjustmentsActual


Denbury


Shongaloo


Pro FormaRevenues

$
72,801


$
160,977


$
912


$
234,690Net income (loss)

$
(115,414
)

$
20,452


$
(2,444
)

$
(97,406
)
 F-19
 Table Of Contents
 NOTE 4 —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). The statement establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:
  Level 1 -
Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.
 Level 2 -
Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.
 Level 3 -
Defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions for the asset or liability.
 Commodity Derivative Instruments— The fair value of the commodity derivative instruments are estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.
 
 Interest Rate Derivative Instruments— The fair value of the interest rate derivative instruments are estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.
 
 As required by the statement, 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, 2010 and 2009.
 
 Partnership - As of December 31, 2010

Total


Level 1


Level 2


Level 3Assets from commodity derivative contracts

$
18,047


$
-


$
18,047


$
-Liabilities from commodity derivative contracts

$
(26,877
)

$
-


$
(26,877
)

$
-
  Predecessor - As of December 31, 2009

Total


Level 1


Level 2


Level 3Assets from commodity derivative contracts

$
7,783


$
-


$
-


$
7,783Liabilities from commodity derivative contracts

$
(67,482
)

$
-


$
-


$
(67,482
)
 As part of the acquisition of the Denbury and Shongaloo acquisitions described in Note 3, the Predecessor performed nonrecurring fair value measurements on the assets acquired. These measurements are classified as Level 3 fair value measurements.
 
 On December 22, 2010, the Predecessor novated certain derivative instruments to us. These derivative instruments were accounted for at fair value on a nonrecurring basis of a $1.4 million net liability position (See Note 5). These derivative instruments are classified as Level 2 fair value measurements.
 
 All fair values reflected above and on the consolidated balance sheets have been adjusted for nonperformance risk. The following table sets forth a reconciliation of the changes in the fair value of the Predecessor’s financial instruments classified as Level 3 in the fair value hierarchy:
  F-20
 Table Of Contents
  PredecessorJanuary 1 to


Year Ended December 31,December 21,2010



2009



2008Balance at beginning of period

$
(59,699
)

$
-


$
-Total gains or losses (realized or unrealized):Included in earnings


25,563



(63,530
)


-Purchases, issuances and settlements


(2,325
)


(45,853
)


-Transfers in and out of Level 3


36,461



49,684



-Balance at end of period

$
-


$
(59,699
)

$
-Changes in unrealized gains relating to derivatives still held at the end of period

$
-


$
(108,164
)

$
-
  As part of a broad review by management of our financial statement disclosures and those of our Predecessor, management has determined, effective October 1, 2010, the fair values of the derivative instruments of our Predecessor should be classified as Level 2. As part of management’s review, the third-party valuation specialist used to value the Predecessor’s derivative instruments was consulted regarding the prices used to determine fair value. Management has determined the prices used by the third-party valuation specialist are directly observable inputs widely used by valuation specialists and easily obtainable from independent third parties via a subscription to their published price curves. Therefore, on October 1, 2010, the Predecessor transferred all derivative instruments which are measured on a recurring basis from Level 3 into Level 2.
 NOTE 5 —DERIVATIVE ACTIVITIES
  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 fluctuation due to changes in both the market price of oil, natural gas and natural gas liquids. We use derivatives to reduce our risk of changes in the prices of oil and natural gas. Our policies do not permit the use of derivatives for speculative purposes.
 
 On the Closing Date, certain of the Fund’s derivative instruments were novated to us. These derivative instruments were transferred to us at fair value as follows:
 
 Short-term derivative instrument asset

$
9,916Long-term derivative instrument asset

$
9,730Short-term derivative instrument liability

$
(5,874
)Long-term derivative instrument liability

$
(15,197
)
  F-21
 Table Of Contents
 The Partnership
 
 As of December 31, 2010, we held swap transaction contracts to manage our exposure to changes in the price of oil and natural gas related to the oil and gas properties. The derivative instruments are fixed for floating swap transactions. As of December 31, 2010, the notional volumes of our commodity contracts were:
 
 Commodity

Index

2011


2012


2013


2014


2015Oil position:Hedged volume (Bbls/d)

WTI


2,238



2,039



2,076



2,090



2,000Average price ($/Bbls)



$
85.00


$
85.25


$
85.35


$
84.58


$
87.40Natural gas position:Hedged volume (MMBtu/d)

NYMEX


9,178



8,192



7,474



7,544



3,398Average price ($/MMbtu)



$
7.26


$
6.45


$
6.45


$
6.30


$
5.52
 
 The Predecessor
 Interest Rate Derivatives
  During June 2010, the Predecessor entered into two tranches of derivative contracts with initial notional amounts of $275.0 million and $135.6 million to effectively fix the LIBOR component of the interest rate on its credit facility. Under the first tranche, the Predecessor will make payments to (or receive payments from) the contract counterparties when the variable interest rate of the one-month LIBOR falls below or exceeds the fixed rate of 2.74% during the period from June 2010 to December 2010. In addition, the Predecessor will make (or receive) payments from the contract counterparties when the one-month LIBOR falls below or exceeds the fixed rate of 1.95% during the period from July 2010 to December 2010 under the second tranche.
 During 2009, the Predecessor had interest rate derivatives for a notional amount of $100 million to effectively fix the LIBOR component of the interest rate on its credit facility at 4.29%. These derivatives expired on October 31, 2009.
 Commodity Derivatives
 In July 2010, the Predecessor entered into an oil collar related to forecast production from January 2014 through December 2015. In September 2010, the Predecessor entered into an offsetting oil collar to reduce hedge volumes from January 2015 through December 2015 associated with the July 2010 oil collar and entered into a swap contract covering the amount of offset volumes.
 
 In December 2008, the Predecessor entered into additional gas basis differential contracts that were based on the Texas Gas Transmission Corporation delivery point.
 
 In November 2008, the Predecessor entered into gas collars that were based on the NYMEX index. The collars are related to forecasted production from January 2010 through December 2010. In December 2008, the Predecessor entered into additional oil and gas collars related to forecasted production from January 2012 through December 2014.
  F-22
 Table Of Contents
 As of December 31, 2009, the notional volumes of the Predecessor’s commodity hedges were:
 Commodity

Index

2010


2011


2012


2013


2014Oil positions:SwapsHedged Volume (Bbls/d)

WTI


3,640



2,961



2,611



2,455



766Average price ($/Bbls)



$
71.20


$
68.25


$
67.54


$
66.80


$
67.93CollarsHedged Volume (Bbls/d)

WTI


-



700



770



70



70Average floor price ($/Bbls)



$
-


$
70.00


$
69.09


$
60.00


$
60.00Average ceiling price ($/Bbls)



$
-


$
110.00


$
107.08


$
77.93


$
77.93Natural gas positions:SwapsHedged Volume (MMBtu/d)

NYMEX


11,272



10,079



4,738



4,387



2,632Average price ($/MMBtu)



$
7.53


$
7.32


$
7.04


$
6.82


$
6.53Basis SwapsHedged Volume (MMBtu/d)

NYMEX


3,797



2,967



2,630



2,473



2,473Average price ($/MMBtu) (1)



$
(0.23
)

$
(0.16
)

$
(0.16
)

$
(0.15
)

$
(0.15
)CollarsHedged Volume (MMBtu/d)

NYMEX


1,611



-



-



-



-Average floor price ($/MMBtu)



$
7.00


$
-


$
-


$
-


$
-Average ceiling price ($/MMBtu)



$
8.90


$
-


$
-


$
-


$
-CollarsHedged Volume (MMBtu/d)

Henry Hub


-



-



2,518



2,518



2,518Average floor price ($/MMBtu)



$
-


$
-


$
6.50


$
6.50


$
6.50Average ceiling price ($/MMBtu)



$
-


$
-


$
8.70


$
8.70


$
8.70
 (1)
Our basis swaps effectively limit our exposure to differences between the NYMEX gas price and the price at the location where we sell our gas. The average prices listed above are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these locational price differences.
 
 F-23
 Table Of Contents
 
 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 accompanying consolidated statements of operations. The fair value of these derivatives was as follows as of December 31:
 
 Partnership


Predecessor2010


2009Asset


Liability


Asset


LiabilityDerivatives


Derivatives


Derivatives


DerivativesCommodity contracts

$
18,047


$
26,877


$
7,783


$
67,482Classification of derivatives on balance sheets:Current

$
9,027


$
7,045


$
7,783


$
14,484Long-term


9,020



19,832



-



52,998$
18,047


$
26,877


$
7,783


$
67,482
 
 The following table presents the impact of derivatives and their location within the consolidated statements of operations for the indicated periods:
 
 Partnership


PredecessorDecember 22 to


January 1 toDecember 31,


December 21,


Year Ended December 31,2010


2010


2009


2008Realized gains (losses):Commodity contracts

$
(289
)

$
5,373


$
47,993


$
(34,666
)Interest rate swaps


-



(4,808
)


(3,299
)


(1,419
)Total

$
(289
)

$
565


$
44,694


$
(36,085
)Unrealized gains (losses):Commodity contracts

$
(7,405
)

$
8,204


$
(111,113
)

$
169,321Interest rate swaps


-



(2,606
)


2,949



(1,932
)Total

$
(7,405
)

$
5,598


$
(108,164
)

$
167,389Total gains (losses):Commodity contracts

$
(7,694
)

$
13,577


$
(63,120
)

$
134,655Interest rate swaps


-



(7,414
)


(350
)


(3,351
)Total

$
(7,694
)

$
6,163


$
(63,470
)

$
131,304
 
 See Note 2 and Note 4 for additional disclosures related to derivative instruments.
  Interest Rate Derivatives
 We made the decision to mitigate interest rate risk with interest rate swaps, which mitigate exposure to market rate fluctuations by converting variable interest rates (such as those on our credit facility) to fixed interest rates. On February 28, 2011, the Predecessor novated certain interest rate swaps to us. Under these swaps, we make payments to, or receive payments from, the counterparties based upon the differential between a specified fixed price and a price related to the three-month LIBOR. We have elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as all payments and receipts on settled contracts, in net gain/loss on derivative contracts in the consolidated statement of operations. See Note 18for a further discussion of the novation.
  F-24
 Table Of Contents
  NOTE 6 —OTHER ASSETS
 
 Other assets comprised the following as of the balance sheet dates indicated:
  Partnership


PredecessorDecember 31,


December 31,2010


2009Property reclamation deposit (1)

$
-


$
10,729Inventories (2)


-



5,496Deferred financing costs, net of amortization


2,645



925Other long-term assets


-



1,539Other assets

$
2,645


$
18,689
 (1)
Property reclamation deposits primarily comprise escrow account security deposits for abandonment and remediation obligations.
 (2)
Inventories primarily comprise drilling pipe which is generally transferred to oil and gas properties when put into service.
 
 NOTE 7 —ASSET RETIREMENT OBLIGATIONS
 
 We recorded a total of approximately $18.3 million for future asset retirement obligations in connection with the conveyance of net assets from the Fund. The total undiscounted amount of future cash flows to settle our asset retirement obligations is estimated to be $58.8 million at December 31, 2010. Payments to settle asset retirement obligations occur over the lives of the oil and gas properties, estimated to be from less than one year to 58 years. Estimated cash flows have been discounted at our credit adjusted risk free rate of 6.3% and adjusted for inflation using a rate of 2.4%.
 
 Changes in the asset retirement obligations are presented in the following table:
  
 Partnership


PredecessorDecember 22


January 1to


to


Year EndedDecember 31,


December 21,


December 31,2010


2010


2009Beginning of period

$
-


$
35,244


$
42,094Assumed in acquisitions


-



24,849



1,732Contribution by Predecessor


18,263







-Divested properties


-







(6,226
)Revisions to previous estimates


-



1,494



1,723Liabilities incurred


-



-



636Liabilities settled


-



(747
)


(8,300
)Accretion expense


25



3,674



3,585End of period

$
18,288


$
64,514


$
35,244Less: Current portion of assetretirement obligations


(1,848
)


(4,187
)


(2,250
)Asset retirement obligations -non-current

$
16,440


$
60,327


$
32,994
  F-25
 Table Of Contents
 
 NOTE 8 —LONG-TERM DEBT
 
 Consolidated debt obligations consisted of the following as of the dates indicated:
 Partnership


PredecessorDecember 31,


December 31,2010


2009Long-term debt:Obligation of Partnership:Senior secured revolving credit facility, variable rate, due December, 2015 (1)

$
225,000


$
-Credit Agreements of Predecessor: (2)Quantum Resources A1, LP, variable rate, due September, 2011


-



79,838QRFC, LP, variable rate, due September, 2011


-



2,939Black Diamond Resources, LLC, variable rate, due September, 2011


-



3,673Total long-term debt

$
225,000


$
86,450Irrevocable stand-by letters of credit:Letters of credit outstanding under credit agreements

$
-


$
14,265
 (1)
As of December 31, 2010, we had availability under this facility of $75 million after giving effect to outstanding borrowings of $225 million.
 
 (2)
As of December 31 2009, our Predecessor had availability under these credit agreements of $27 million after giving effect to outstanding borrowings of $86.5 million and $14.3 million in outstanding letters of credit.
 
 The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable debt obligation during the period from December 22 to December 31, 2010:
 
 The Partnership
  Range of
Weighted AverageInterest Rates Paid (1)
Interest Rate Paid (1)Senior secured revolving credit facility
2.8% to 4.8%
4.6%
  (1)
Our interest rate for the period from December 22, 2010 through December 31, 2010 was 4.8% for 9 days as the rate was an alternate base rate. On December 31, 2010 the rate reset to a LIBOR-based rate.  The Predecessor novated interest rate derivatives to us effective February 28, 2011 to fix the LIBOR rate in our credit facility to a 1.87% weighted average rate for the term of the 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 syndication of banks (the “Credit Agreement”). Initial borrowings under the Credit Agreement on the Closing Date were $225 million.
  The Credit Agreement is a five-year, $750 million revolving credit facility, with a borrowing base of approximately $300 million as of December 31, 2010. The borrowing base will be subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, natural gas and NGL reserves, which will take into account the prevailing oil, natural gas and NGL prices and associated differentials at such time, which is then adjusted for the impact of our commodity derivative contracts. 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%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum.
  The Credit Agreement requires us to maintain a leverage ratio (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 its assets; make certain investments, acquisitions or other restricted payments (including a prohibition on our ability to pay distribution to our unitholders if our borrowing base usage exceeds 95%); modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and to provide audited financial statements within 105 days of year end and reviewed quarterly 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 its forecasted production attributable to proved developed producing reserves and (ii) 85% of its forecasted production from total proved reserves for the next two years and 75% of its 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, 2010, we were in compliance with all of the Credit Agreement covenants, however, we did not provide our audited financial statements by April 15, 2011 for which we sought and received a waiver to extend this reporting requirement by 30 days from our lenders.
  F-26
 Table Of Contents
  In connection with the IPO, we assumed $200 million of the Predecessor’s debt. On the Closing Date, we repaid the assumed debt with the proceeds from our revolving credit facility disclosed above.
 The Predecessor
 
 In September 2006, the Predecessor, through its subsidiaries QRA1, QRFC, and Black Diamond entered into three separate five-year revolving credit agreements with a syndicated bank group (the “Predecessor Credit Facilities”). The combined Predecessor Credit Facilities had a maximum commitment of $840 million and a current conforming borrowing base of $127.8 million at December 31, 2009.
 
 The Credit Facilities for QRA1 and Black Diamond were held by mortgages on their oil and gas properties and related assets. QRFC’s credit facility was held by the oil and gas properties owned by QAC.
 
 Borrowings under the Predecessor Credit Facilities bore interest at the Alternative Base Rate (ABR) or the Eurodollar Rate plus a margin based on the borrowing base utilization. The ABR is defined as the higher of the prime rate or the sum of the Federal Funds Effective Rate plus 0.5%. The Eurodollar Rate is defined as the applicable British Bankers’ Association London Interbank Offered Rate (LIBOR) for deposits in U.S. dollars.
  In addition, the credit agreements had $14.3 million in outstanding letters of credit as of December 31, 2009 primarily related to the Jay Field abandonment and insurance requirements.
  On May 14th, 2010 the Predecessor terminated its existing credit facilities and, through three of its subsidiaries, entered into three separate four-year revolving credit agreements. All outstanding loans under the previous credit facility were repaid in full from borrowings from the new credit facilities and all remaining unamortized loan costs totaling $0.7 million were written off. The combined new credit facilities had a maximum commitment of $850 million and a current conforming borrowing base of $650 million. In conjunction with the amendments, the Predecessor incurred $11.5 million of debt issuance costs which were capitalized and are being amortized over the term of the agreements. Concurrent with the IPO, the Predecessor's borrowing base was reduced to $415 million.
 The credit agreements require the Predecessor to maintain a leverage ratio of not more than 4.5 to 1.0 currently, decreasing to 4.0 to 1.0 beginning with the period ended September 30, 2011 and continuing through maturity, and a current ratio of not less than 1.0 to 1.0. Additionally, the credit agreements contain various covenants and restrictive provisions which limit the Predecessor’s ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its 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 require delivery of audited financial statements within 120 days of the end of each fiscal year and reviewed quarterly financial statements within 45 days of the end of each quarter. The credit agreements also provide limits on the amount of commodity derivative contracts the Predecessor may enter into, in particular prohibiting the Predecessor from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of its forecasted production attributable to proved developed producing reserves and (ii) 85% of its forecasted production from total proved reserves for the next two years and 75% of its forecasted production thereafter. If the Predecessor fails to perform its obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the credit agreements, together with accrued interest, could be declared immediately due and payable. As of December 31, 2010, the Predecessor was in compliance with all covenants in its credit agreements, however, the Predecessor did not provide its audited financial statements by April 30, 2011 for which it sought and received a waiver to extend this reporting requirement by 45 days.
 NOTE 9 —COMMITMENTS AND CONTINGENCIES
 
 Services Agreement
  The Partnership
  We have entered into a Services Agreement with QRM as described in Note 15, under which, QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. The Partnership has no other commitments as of December 31, 2010.
  Operating Lease Commitments
 
 The Predecessor
 
 Approximately 87% of the Predecessor’s future minimum rental payments are derived from the Houston corporate office space sublease which commenced September 1, 2009 and terminates December 31, 2012. The leasing agreement contains a four month rent holiday to be taken from the commencement date. A $1.6 million fee was paid by the Predecessor to terminate the Denver corporate office space lease on November 15, 2009. Total rental expense for the Predecessor for the period from January 1, 2010 to December 21, 2010 and for 2009 and 2008 was approximately $0.8 million, $3.0 million and $1.0 million.
  F-27
 Table Of Contents
  Legal Proceedings
 
 The Partnership
 
 We are involved in one dispute or legal action arising in the ordinary course of business. We do not believe the outcome of such dispute or legal action will have a material adverse effect on our consolidated financial statements, so no amounts have been accrued as of December 31, 2010.
 
 In addition, we do not have any working interests in the Jay Field and are therefore not a party to the Predecessor’s pending legal proceedings discussed below.
 
 The Predecessor
 
 The Predecessor is involved in various suits and claims arising in the normal course of business. The Predecessor related entities owning record working interest in the Jay Field, brought suit against Santa Rosa County, Florida, protesting the County’s assessed value for the Jay interests for calendar years 2009 and 2010. Santa Rosa County assessed the value of the Jay Field at approximately $92 million for each year.  The Predecessor made good faith payments for each calendar year based on valuations of $5 million and $45 million.  If the County were to prevail in its assessed value, the resulting additional tax to the Predecessor will be approximately $1.3 million for 2009 and $0.8 million for 2010. The Predecessor believes it has a sound case to prevail on an assessed value lower than that asserted by Santa Rosa County for each calendar year.
  In April 2011, the Predecessor received a demand letter from a third-party for severance taxes related to production for the past ten years from an operating unit. The total amount claimed is approximately $2 million. Based on an initial evaluation, the Predecessor believes there is no evidence to support a material liability.
  In management’s opinion, the ultimate outcome of these items will not have a material adverse effect on the Predecessor’s consolidated results of operations, financial position or cash flows. Based on management’s assessment, no contingent liabilities have been recorded as of December 31, 2009 and December 21, 2010.
 
 NOTE 10 — OWNERS’ EQUITY
 
 Initial Public Offering
 
 On December 22, 2010, we completed our IPO of 15,000,000 common units representing limited partner interests in us at $20.00 per common unit, or $18.70 per unit after payment of the underwriting discount. In connection with the IPO, the Fund contributed to us certain fields in the Permian Basin and the Ark-La-Tex, Mid-Continent and Gulf Coast areas. In exchange, the Fund received, either directly or through our assumption of its indebtedness, all of the net proceeds of the IPO. Upon completion of the IPO, we had 26,297,737 common units, 7,145,866 subordinated units and 35,729 general partner units outstanding. Our common units are traded on the NYSE under the symbol “QRE.”
 
 All of the subordinated units and 11,297,737 common units are owned by the Fund and all of the general partner units are owned by affiliates of the Fund.
 
 Units Outstanding
 
 As of December 31, 2010, partners’ capital consisted of 26,297,737 outstanding common units and 7,145,866 outstanding subordinated units, representing a 99.9% limited partnership interest in us, and a 0.1% QRE general partnership interest comprising 35,729 units.
 
 Common Units
 
 The common units have limited voting rights as set forth in our partnership agreement.
  F-28
 Table Of Contents
  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 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.
 
 Subordinated Units
 
 The principal difference between our common and subordinated units is that, in any quarter during the subordination period, the subordinated units are entitled to receive the minimum quarterly distribution of $0.4125 per unit ($1.65 per unit on an annualized basis) only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.
 
 The subordination period will end on the earlier of:
 
 ·
the later to occur of (i) the second anniversary of the closing of our IPO and (ii) such date as all arrearages, if any, of distributions of the minimum quarterly distribution on the common units have been eliminated; and
 
 ·
the removal of QRE GP other than for cause, provided that no subordinated units or common units held by the holders of the subordinated units or their affiliates are voted in favor of such removal.
 
 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.
 
 Allocations of Net Income
 
 Net income is allocated between QRE GP and the common and subordinated unitholders in proportion to their pro rata ownership during the period.
 
 Cash Distributions
 
 We intend to continue to make regular 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 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 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.
  F-29
 Table Of Contents
  QRE GP owns a 0.1% general partner interest in us, represented by 35,729 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 these 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.
 
 Our partnership agreement requires that within 45 days after the end of each quarter, beginning with the quarter ended December 31, 2010, we distribute all of our available cash to 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.
  ·
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.
 
 During Subordination Period.Our partnership agreement 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 unit 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, pro rata;
 
 After Subordination Period.Our partnership agreement requires that after the subordination period, we make distributions of available cash from operating surplus for any quarter to QRE GP and all unitholders in accordance with their percentage interest, pro rata
  F-30
 Table Of Contents
  NOTE 11 —NET LOSS PER LIMITED PARTNER UNIT
 The following sets forth the calculation of net loss per limited partner unit for the period from December 22, 2010 through December 31, 2010:
 Net loss

$
(7,099
)Less:General partner's 0.1% interest in net loss


(7
)Limited partners' interest in net loss

$
(7,092
)Weighted average limited partner units outstanding:Common units


26,298Subordinated units (1)


7,146Total


33,444Net loss per limited partner unit (basic and diluted)

$
(0.21
)
 (1)
Our subordinated units are considered to be participating securities for purposes of calculating our net income per limited partner unit, and accordingly, are included in the basic computation as such.
 
 Net income per limited partner unit is determined by dividing the net income available to the common unitholders, after deducting QRE GP’s 0.1% interest in net income, by the number of common units and subordinated units outstanding as of December 31, 2010. The aggregate number of common units and subordinated units was 26,297,737 and 7,145,866. All units were outstanding since December 22, 2010.
  F-31
 Table Of Contents
 
 NOTE 12 — EQUITY-BASED COMPENSATION
 
 Partnership Unit - Based LTIP Plan
  On December 22, 2010, in connection with the closing of the IPO, the Board of Directors of QRE GP adopted the QRE GP, LLC Long Term Incentive Plan (the “Plan”) for employees, officers, consultants and directors and consultants of QRE GP and those of 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 long-term incentive plan is to provide additional incentive compensation to employees providing services to us and to align the economic interests of such employees with the interests of our unitholders. The Plan 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.
 
 On December 22, 2010, we granted awards to individuals who performed services for us in support of the completion of our IPO. For the period from December 22, 2010 to December 31, 2010, we recognized compensation expense related to these awards of less than $0.1 million. As of December 31, 2010, we had 148,150 restricted unit awards outstanding with a grant date fair value of $2.8 million which we expect will be recognized in expense over periods up to five years.
 
 The following table summarizes the Partnership’s unit-based awards from December 22, 2010 through December 31, 2010 (in thousands):
  Number of


WeightedUnvested


AverageRestricted


Grant-DateUnits


Fair ValueOutstanding at beginning of period


-


$
-Granted


148



20.03Outstanding at end of period


148


$
20.03
 Predecessor Compensation Plans
 
 Long-Term Incentive Compensation Plan
 
 In April 2009, the Predecessor adopted a Long-Term Incentive Compensation Plan "Agreement" for its executive officers and other key employees. These employees receive certain interest, as defined below, in distributions received by the Predecessor through its subsidiaries. During the period ended December 31, 2010 the Predecessor recognized compensation expense of $1.6 million in equity-classified awards and $1.9 million in liability-classified awards. These awards are based on certain performance measurements and service. Interests awarded are based on the type of interest held by the Predecessor or its subsidiaries as follows:
 
 The Predecessor General Partnership (Funded) Interest
 
 The Predecessor contributes to the Fund 3% of all equity contributions made to the Fund and receives 3% of any distributions made by the Fund ("GP Funded Interest").  A special class of limited partnership interest in the general partner of the Fund was created to give executive officers and other key employees an interest in the GP Funded Interest after the Predecessor has recouped a portion of its total capital contributed to the Fund until each employee has received a cumulative amount equal to his vested share of the GP Funded Interest. Employees awarded this interest vest 15% on each of the first five anniversaries of the effective date and the remaining 25% vests if employed upon the disposition of substantially all of the assets of the Fund.
  Employees of the Predecessor received GP Funded Interest grants in 2010 and 2009.  The estimated fair value, at the date of the grant, is recognized as long-term incentive compensation  in  general and administrative expense in the statement of operations ratably as the awards vest. Estimated forfeitures will be adjusted to reflect actual forfeitures in future periods. We account for these profits interests as equity awards, and we estimated the fair value of these interests using a Probability Weighted Expected Return Model (“PWERM”). The PWERM forecasts expected cash flow scenarios specific to each award, assigns probability weights to these scenarios, then discounts the sum of the probability weighted cash flows to a grant date present value using a risk adjusted discount rate.  The scenarios represent possible outcomes for each award based on assumptions about investment horizon, cash flow amounts and timing, asset values, commodity prices, equity investment amounts, and return on investment. The Predecessor assumed a zero percentage forfeiture rate for all years when determining the fair value of the GP Funded Interest.
 
 The  estimated  aggregate  fair  value of the equity component of theawards at the date of grant was $0.3 million and $0.7 million for awards granted during the periods ended December 21, 2010 and December 31, 2009 respectively.  The Predecessor incurred non-cash  compensation expense related to the GP Funded Interest awards of $0.2 million and $0.1 million for the periods ended December 21, 2010 and December 31, 2009.  The 2009 expense was recorded in 2010.  Refer to "Out-of-Period Adjustments" further below.  In addition, there is a liability component to the award related to the 25% that vests and will be expensed upon substantial disposition of the Fund assets with a fair value of $0.7 million at December 21, 2010.
  F-32
  Activity related to the GP Funded Interests is as follows:% of

Interest

Granted


Weighted

Average

Grant Date

Fair Value

Per 1%Nonvested GP Funded Interests as of December 31, 2008


0.00
%

$
-Granted


72.82
%


57,512Forfeited


0.00
%


-Nonvested GP Funded Interests as of December 31, 2009


72.82
%

$
57,512Granted


22.05
%


88,206Forfeited


0.00
%


-Nonvested GP Funded Interests as of December 21, 2010


94.87
%

$
145,718
 
 Activity related to the GP Funded Interests is as follows:Nonvested GP Funded Interests as of December 31, 2008


0.00%Granted


72.82%Vested


0.00%Forfeited


0.00%Nonvested GP Funded Interests as of December 31, 2009


72.82%Granted


22.05%Vested


-10.92%Forfeited


0.00%Nonvested GP Funded Interests as of December 21, 2010


83.95%
 
 The Predecessor General Partner Promote Interest
 
 After all investors in the Fund have received a return of their equity contributions plus a return of 8%, the Predecessor is entitled to receive 14% of all amounts distributed thereafter, including a catch-up on the amount distributed as part of the 8% return to all investors ("GP Promote"). A special class of limited partnership interest was created to award executive officers and other key employees 100%  of the interest in the GP Promote until distributions attributable to the GP Promote aggregate $12,800,000 and thereafter 39% of the distributions attributable solely to the GP Promote. Employees awarded this interest vest 15% on each of the first five anniversaries of the effective date and the remaining 25% vests if employed upon the disposition of substantially all of the assets of the Fund.
  Employees of the Predecessor received GP Promote grants in 2010 and 2009.  The estimated fair value, at the date of the grant, is recognized as compensation  in general and administrative expense in the statement of operations ratably as the awards vest. Estimated forfeitures will be adjusted to reflect actual forfeitures in future periods.  In accordance with GAAP, we estimated the fair value of these interests using a Probability Weighted Expected Return Model (“PWERM”). The PWERM forecasts expected cash flow scenarios specific to each award, assigns probability weights to these scenarios, then discounts the sum of the probability weighted cash flows to a grant date present value using a risk adjusted discount rate.  The scenarios represent possible outcomes for each award based on assumptions about investment horizon, cash flow amounts and timing, asset values, commodity prices, equity investment amounts, and return on investment. The Predecessor assumed a zero percentage forfeiture rate for all years when determining the fair value of the GP Promote.
 
 The  estimated  aggregate  fair  value of the equity component of the awards at the date  of grant was $0.3 million and $0.9 million for awards granted during the periods ended, December 21, 2010 and December 31, 2009, respectively. The Predecessor incurred non-cash  compensation  expense of $0.2 million and $0.1 million for the periods ended  December 21, 2010 and December 31, 2009.  The 2009 expense was recorded in 2010.  Refer to "Out-of-Period Adjustments" further below.  No amounts have been forfeited.  In addition, there is a liability component to the award related to the 25% that vests and will be expensed upon substantial disposition of the Fund assets with a fair value of $1.1 million at December 21, 2010.
 
 Activity related to the GP Promote Interests is as follows:% of

Interest

Granted


Weighted

Average

Grant Date

Fair Value

Per 1%Nonvested GP Promote Interests as of December 31, 2008


0.00
%

$
-Granted


78.83
%


71,534Forfeited


0.00
%


-Nonvested GP Promote Interests as of December 31, 2009


78.83
%

$
71,534Granted


17.45
%


97,544Forfeited


0.00
%


-Nonvested GP Promote Interests as of December 21, 2010


96.28
%

$
169,078
 
 Activity related to the GP Promote Interests is as follows:Nonvested GP Promote Interests as of December 31, 2008


0.00%Granted


78.83%Vested


0.00%Forfeited


0.00%Nonvested GP Promote Interests as of December 31, 2009


78.83%Granted


17.45%Vested


-10.92%Forfeited


0.00%Nonvested GP Promote Interests as of December 21, 2010


85.36%
 
 F-33
  Purchase/Carry Interests
 
 The Predecessor, through a subsidiary, purchases a 2% interest in each property acquired by the Fund and also receives a 2% carried interest in each property acquired by the Fund. A special class of  limited  partnership  interests  in the Predecessor was created and awarded on April 1, 2009 to two senior executive officers in the aggregate of 19.5% of the distributions made by the subsidiary ("Purchase/Carry Interest") excluding an amount that represented the net agreed value of the subsidiary assets on the date of grant. The Purchase/Carry Interests vest (i) 50% upon the effective date of the grant, (ii) an additional 7.5% on each of the first five anniversaries following April 1, 2009 and (iii) the remaining 12.5% vest if employed upon the disposition of substantially all of the assets of the Fund.  In addition, the executives must be employed as of the Fund's investment period, currently June 30, 2011, and the Fund must achieve a 1.5X return on its total capital investment, as defined by the Agreement.
 
 The  estimated fair value, at the date of the grant, is recognized as compensation  in general and administrative expense in the statement of operations ratably as the awards vest. Estimated forfeitures will be adjusted to reflect actual forfeitures in future periods.  In accordance with GAAP, we have accounted for the fair value of the Purchase/Carry Interests as equity awards, and we estimated the fair value of these interests using a Probability Weighted Expected Return Model (“PWERM”). The PWERM forecasts expected cash flow scenarios specific to each award, assigns probability weights to these scenarios, then discounts the sum of the probability weighted cash flows to a grant date present value using a risk adjusted discount rate.  The scenarios represent possible outcomes for each award based on assumptions about investment horizon, cash flow amounts and timing, asset values, commodity prices, equity investment amounts, and return on investment. The Predecessor assumed a zero percentage forfeiture rate for all years when determining the fair value of the Purchase/Carry Interests.
 
 The  estimated  aggregate  fair  value of the equity component of the awards at the date  of grant was $1.8 million.  the Predecessor incurred non-cash  compensation  expense of $0.6 million and $0.4 million for the periods ended  December 21, 2010 and December 31, 2009.  The 2009 expense was recorded in 2010.  Refer to "Out-of-Period Adjustments" further below.  No amounts have been forfeited. In addition, there is a liability component to the award related to the 12.5% that vests and will be expensed upon substantial disposition of the Fund assets with a fair value of $0.3 million at December 21, 2010.
 
 Activity related to the Purchase/Carry Interests is as follows:% of

Interest

Granted


Weighted

Average

Grant Date

Fair Value

Per 1%Nonvested Purchase/Carry Interests as of December 31, 2008


0.00
%

$
-Granted


100.00
%


13,278Forfeited


0.00
%


-Nonvested Purchase/Carry Interests as of December 31, 2009


100.00
%

$
13,278Granted


0.00
%


-Forfeited


0.00
%


-Nonvested Purchase/Carry Interests as of December 21, 2010


100.00
%

$
13,278
 
 Activity related to the GP Funded Interests is as follows:Nonvested Purchase/Carry Interests as of December 31, 2008


0.00%Granted


100.00%Vested


0.00%Forfeited


0.00%Nonvested Purchase/Carry Interests as of December 31, 2009


100.00%Vested


-7.50%Forfeited


0.00%Nonvested Purchase/Carry Interests as of December 21, 2010


92.50%
  F-34
 
 Performance Cash Deferred Compensation Plan
 
 In April 2009, the Predecessor established a bonus plan ("Bonus Pool") for certain key employees to award these employees upon the Fund achieving certain performance targets and service by the employee. If the Fund achieves a 1.75X return on its total capital investment ("1.75X ROI") as defined in the plan, a Bonus Pool of $12.5 million will be established for the employees. If the Fund achieves a 2.0X return on its capital investment the Bonus Pool will be increased to $15 million.
 
 Each employee will vest in a pro-rata share of the Bonus Pool, as determined by their offer letter, 15% per year from the date of the grant for five years and 25%  upon the disposition of substantially all of the assets of the Fund.  The employee must remain employed for the vesting period and must be employed on the date upon which the disposition of substantially all of the assets of the Fund occurs.
 
 During the fourth quarter 2010, the Predecessor determined that it was probable to meet the 1.75X ROI and has recorded $1.9 million of compensation expense in general and administrative expenses in the statement of operations for the year ended December 21, 2010. These awards are liability-classified awards as they will ultimately settle in cash.
 
 Out of Period Adjustments
 
 During 2010 the Predecessor recorded adjustments related to 2009 which decreased its income for 2010 by $0.6 million as a result of compensation expense which should have been recorded in 2009.
 
 After evaluating the quantitative and qualitative aspects of these errors, the Predecessor concluded its previously issued financial statements were not materially misstated and the effect of recognizing these adjustments in the 2010 financial statements were not material to the 2010 results of operations, financial position and cash flows.
 NOTE 13 — NATURAL GAS IMBALANCES
 
 We account for our natural gas imbalances under the sales method. We had overproduced liabilities of $1.2 million included in accrued liabilities on our consolidated balance sheet as of December 31, 2010 for overproduced positions which we have no remaining natural gas reserves.
 
 As of December 31, 2010, our gross underproduced natural gas position was approximately $1.8 million (597 MMcf) and our gross overproduced natural gas position was approximately $2.2 million (590 MMcf). These gross positions were valued at $4.00 per Mcf without regard to remaining natural gas reserves.
 
 As of December 31, 2009, the Predecessor had over produced liabilities of $0.8 million of natural gas imbalance positions.
 
 NOTE 14 — SIGNIFICANT CUSTOMERS
 
 The following table indicates our significant customers which accounted for more than 10% of our total revenues for the periods indicated:
  Partnership


Predecessor2010(1)


2010(1)


2009


2008ConocoPhillips


23
%



(2)



(2)



(2)Plains Marketing LP


16
%



(2)


10
%



(2)Shell Trading US Company


10
%


45
%


24
%


51
%Sunoco Inc R&M



(2)


10
%


12
%



(2)
  (1)
In 2010, we evaluated concentration of credit risk for us and the Predecessor by analyzing customer receipts from the oil and gas assets as if the title to the properties at the IPO Closing Date were in existence for the entire year.
 
 (2)
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 its ability to sell its natural gas or crude oil production.
 F-35
 Table Of Contents
 NOTE 15 —RELATED PARTY TRANSACTIONS
 
 Ownership in QRE GP by the Management of the Fund and its Affiliates
 
 As of December 31, 2010, affiliates of the Fund owned 100% of QRE GP and an aggregate of approximately 43% of the outstanding common units and all of the subordinated units representing limited partner interests in us. In addition, QRE GP owned a 0.1% general partner interest in us, represented by 35,729 general partner units.
  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.
  Contribution Agreement
 
 On December 22, 2010, in connection with the closing of the IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement by and among the Partnership, QRE GP, OLLC and the Fund:
  ·
QRE GP agreed to contribute $0.7 million to the Partnership to maintain its 0.1% general partner interest in the Partnership, represented by 35,729 general partner units; and
  ·
The Fund contributed net assets of $223.7 million to the Partnership in exchange for 11,297,737 common and 7,145,866 subordinated limited partner units and a $300 million cash distribution. See Note 1.
  QRE GP’s capital contribution remained as a receivable on the Partnership’s books as of December 31, 2010 and was received by the Partnership in January 2011.
 
 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 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 will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. For the period from the closing of the IPO through December 31, 2010, we incurred approximately $0.1 million for the administrative services fee under the Services Agreement.
  The term of the Services Agreement comprises an initial term from December 22, 2010 to December 31, 2010 and continues on a year-to-year basis thereafter unless terminated after the initial term by us or QRM. After the term of the Services Agreement ends, in lieu of the quarterly administrative services fee, QRE GP will reimburse QRM, on a quarterly basis, for the allocable expenses QRM incurs in its performance under the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM. 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 QRM to its affiliates.
  F-36
 Table Of Contents
  The following table summarizes transactions under the Services Agreement between us and the Fund during the period from December 22, 2010 to December 31, 2010:
 
 December 22toDecember 31,2010Ad valorem taxes paid by the Fund on our behalf

$
22Interest paid by the Fund on our behalf


263Debt issue costs paid by the Fund on our behalf


102Intercompany financing from the Fund


387Administrative services fee due to the Fund


55Net increase in affiliate payable

$
442General and administrative expense allocated from the Fund (1), (2)

$
184
 (1)
Represents amounts allocated to us from the Fund in excess of the administrative service fee to reflect general and administrative expenses we would incur as a stand-alone entity.
 
 (2)
Allocated general and administrative expenses have been recorded as other contributions in our consolidated statement of owners’ equity.
 
 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 $150 million of its unfunded committed equity capital. 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. In addition to opportunities to purchase proved reserves from, and to participate in future acquisition opportunities with, the Fund, if QA Global or its affiliate establishes another fund to acquire oil and natural gas properties within two years of the closing of the IPO, QA Global will cause such fund to provide us with a similar right to participate in such fund’s acquisition opportunities. These contractual obligations will remain in effect 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 Closing Date of our IPO. 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.
  F-37
 Table Of Contents
  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 period from December 22, 2010 to December 31, 2010, no management incentive fees were earned by or paid to our QRE GP.
 
 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, 2010, 148,150 restricted unit awards with a fair value $2.8 million were granted under the Plan. For additional discussion regarding the Plan see Note 12.
 
 Distributions of available cash to our QRE GP and affiliates
  We will generally make cash distributions to our unitholders and QRE GP pro rata, including our QRE GP and our affiliates. As of December 31, 2010, QRE GP and its affiliates held 11,297,737 common units, all of the subordinated units and 35,729 QRE GP units. No cash distributions were made from December 22, 2010 through December 31, 2010. The Partnership made a cash distribution on February 11, 2011 as discussed in Note 19.
  Our relationship with Bank of America
  Don Powell, one of our independent directors, is also a director of Bank of America (“BOA”). BOA is a lender under our Credit Agreement.
  F-38
 Table Of Contents
 NOTE 16 – PREDECESSOR’S UNCONSOLIDATED INVESTMENT IN UTE ENERGY, LLC
  Ute Energy, LLC (“Ute”), a Delaware limited liability company, was formed on February 2, 2005 for the purpose of developing the mineral and surface estate of the Ute Indian Tribe by participating in oil and gas exploration and development, as well as the construction and operation of gas gathering and transportation facilities. Ute’s properties are located on the Uintah and Ouray Reservation in northeastern Utah. On July 9, 2007, the Predecessor initially acquired an interest in Ute and accounts for the investment using the equity method of accounting.
 During 2008, the Predecessor recorded an other-than-temporary impairment of $2.6 million in the carrying value of its investment. There were no impairments during the period from January 1, 2010 to December 21, 2010 or during 2009.
 
 During 2008 and 2009, the Predecessor purchased additional ownership interests in Ute bringing their total ownership percentage to 25% as of December 31, 2009.
 
 In March 2010, as part of the wider recapitalization of Ute, the Predecessor exchanged its 2,929,471 redeemable units for 2,929,471 common units and was issued an additional 175,126 redeemable units. This share-for-share exchange resulted in a gain of $4,064,000. The non-cash recapitalization converted certain of the redeemable units into Class A common units at a valuation of $10 per unit, with the remaining 175,126 redeemable units that will accrue a return equal to 12% per annum, being retained by the Predecessor. The overall recapitalization resulted in a decrease in the Predecessor’s common unit class ownership from 25% to 23.8%.
 
 The Predecessor’s equity in earnings of Ute was $3.8 million, $2.7 million and ($3.0) million for the period of January 1, 2010 through December 21, 2010 and for the years ended December 31, 2009 and 2008. The Predecessor’s unconsolidated investment in Ute was $41.6 million as of December 31, 2009.
 
 The following table shows summarized financial information of the Predecessor’s investment in Ute for the periods indicated:
 
 January 1 toDecember 21,2010


2009


2008Revenues

$
37,818


$
10,025


$
14,832Operating expenses


(27,071
)


(14,059
)


(17,310
)Operating profit (loss)


10,747



(4,034
)


(2,478
)Interest expense


(2,192
)


(2,275
)


(1,156
)Other income/(expense)


7,163



4,999



4,890Net income (loss)

$
15,718


$
(1,310
)

$
1,256
 
 
 December 31,2009Current assets

$
2,288Property and equipment, net


34,417Equity method investments


94,248Other assets


1,978Total assets

$
132,931Current liabilities

$
5,538Long-term liabilities


52,010Members’ equity


75,383Total liabilities and members’ equity

$
132,931
 F-39
 Table Of Contents
  NOTE 17 – SUPPLEMENTAL CASH FLOW INFORMATION
 
 Supplemental cash flow information was as follows for the periods indicated:
 
 Partnership


PredecessorDecember 22


January 1to


toDecember 31,


December 21,


Year Ended December 31,2010


2010


2009


2008CashCash paid during the period for interest

$
263


$
11,244


$
2,480


$
9,000Cash paid for state income tax


-



108



182



149NoncashNet assets contributed by the Fund

$
223,736


$
-


$
-


$
-Change in accrued capital expenditures


39



6,906



(11,206
)


3,828Insurance premium financed


1,308



2,075



1,695



-Additions (reductions) to asset retirement obligations


-



747



(10,435
)


1,370Contributions receivable from QRE GP


715



-



-



-
  F-40
  NOTE 18 – SUBSEQUENT EVENTS
 
 The Partnership
  In preparing the accompanying financial statements, we have reviewed events that have occurred after December 31, 2010, up until the issuance of the financial statements.
 
 On January 3, 2011, the underwriters exercised their full over-allotment option for an additional 2,250,000 common units issued by the Partnership at $20.00 per unit. Total net proceeds from the sale of these common units, after deducting estimated offering costs, were approximately $42 million.
 
 On January 25, 2011, the board of directors of QRE GP declared a $0.0448 per unit distribution for the period from December 22, 2010 through December 31, 2010 on all limited partner units. The distribution was paid on February 11, 2011 to unitholders of record at the close of business on February 7, 2011. The aggregate amount of the distribution was $1.6 million.
 
 On January 4, 2011, we granted common unit awards of 3,750 units to each of our independent directors. The fair value of the common unit awards granted was calculated based on the closing price of our common units on the grant date, $20.20 per common unit.
  On February 28, 2011, the Predecessor novated to the Partnership LIBOR-based interest rate swaps. In conjunction with the novation, the Partnership has the following open derivative contracts:
 Period

Weighted Average

Fixed LIBOR Rate

Notional

Amount2011

1.88%

$225 million2012

1.88%

$225 million2013

1.87%

$225 million2014

1.87%

$225 million2015

1.87%

$225 million
  On March 9, 2011, we granted common unit awards of 8,985 units to two of our named executive officers. The fair value of the common unit awards granted was calculated based on the closing price of our common units on the grant date, $22.26 per common unit.
 
 The Predecessor
 
 Subsequent to the IPO, the Predecessor signed and closed a purchase agreement on December 22, 2010 to acquire certain oil and gas properties from Melrose Energy Company for $62.3 million.
 
 On the Closing Date, as described in Note 1, the Predecessor contributed to the Partnership reserves totaling 30,491 MBoe, or 36% of the total 83,880 MBoe in reserves held by the Predecessor at the contribution date.
  F-41
 Table Of Contents
  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 December 31, 2010 and 2009:
 
 Partnership


PredecessorDecember 31,

2010


December 31,

2009Proved oil and natural gas properties

$
444,710


$
709,552Unproved oil and natural gas properties


-



-444,710



709,552Accumulated depreciation, depletion and amortization


(913
)


(589,694
)Net capitalized costs

$
443,797


$
119,858
  Pursuant to the FASB’s authoritative guidance on asset retirement obligations, net capitalized costs include asset retirement costs of $18.3 million and $29.6 million as of December 31, 2010 and 2009.
 
 Costs Incurred
 
 Our oil and natural gas activities are conducted in the United States. The following table summarizes the costs incurred by us:
 
 Partnership


PredecessorDecember 22 to


January 1 toDecember 31,


December 21,


Year ended December 31,2010


2010


2009


2008Acquisition of oil andnatural gas properties:Proved

$
-


$
872,829


$
49,145


$
391Unproved


-



43,000



-



-Development costs


-



60,567



7,152



88,916Total

$
-


$
976,396


$
56,297


$
89,307
 Estimated Proved Reserves
 
 Recent SEC and FASB Guidance.In December 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. The Predecessor adopted the rules effective December 31, 2009, and the rule changes, including those related to pricing and technology, are included in our and the Predecessor’s reserve estimates.
 
 Third Party Reserves Estimate. The reserve estimates as of December 31, 2010 and 2009 presented in the table below were based on reserve reports prepared by Miller & Lents, Ltd., independent reserve engineers, using FASB and SEC rules in effect as of December 31, 2010 and 2009. The reserve estimates as of December 31, 2008 in the table below were based on reserve reports prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers, using the FASB rules in effect as of December 31, 2008.
 
 Oil and Gas Reserve Quantities.Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made.
 
 Prices include consideration of changes in existing prices provided only by contractual arrangement, but not on escalations based on future conditions. All of the Partnership’s oil and natural gas producing activities were conducted within the continental United States.
  F-42
 Table Of Contents
  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.
 
 Following is a summary of the proved developed and total proved oil and natural gas reserves attributed to our operations:
  NaturalOil


Gas


NGL(MBbl)


(MMcf)


(MBbl)Partnership:Balance, December 22, 2010


-



-



-Contribution from Predecessor


19,511



57,700



1,363Production


(26
)


(141
)


(4
)Balance, December 31, 2010


19,485



57,559



1,359Proved developed reserves:December 31, 2010


11,578



47,559



1,305Predecessor:Proved reserves:Balance, December 31, 2007


23,247



88,880



-Purchases of reserves in place


-



-



-Revisions of previous estimates


(13,312
)


(48,547
)


-Production


(1,753
)


(5,590
)


-Balance, December 31, 2008


8,182



34,743



-Purchases of reserves in place


262



20,169



1,327Sale of reserves in place


(442
)


(5,981
)


-Revisions of previous estimates


1,045



1,760



966Production


(739
)


(5,359
)


(207
)Balance, December 31, 2009(1)


8,308



45,332



2,086Purchases of reserves in place


21,890



243,835



2,592Revisions of previous estimates


5,653



(1,050
)


244Production


(2,172
)


(14,753
)


(282
)Balance, December 21, 2010(2)


33,679



273,364



4,640Proved developed reserves:December 31, 2008


6,301



33,224



-December 31, 2009


6,721



44,879



2,037December 21, 2010


24,313



198,160



4,411
  (1)
These reserves include 7,740 MBbl, 42,235 MMcf and 1,943 MBbl of Oil, Natural Gas and NGLs attributable to an approximate 93.2% noncontrolling interest in the Predecessor as of December 31, 2009.
  (2)
These reserves include 31,767 MBbl, 257,843 MMcf and 4,377 MBbl of Oil, Natural Gas and NGLs attributable to an approximate 94.3% noncontrolling interest in the Predecessor as of December 21, 2010.
 Purchases of Reserves in Place. The 24,482 MBbl of liquids and 243,835 MMcf of natural gas purchased in 2010, was associated with the Denbury acquisition.The 1,589 MBbl of liquids and 20,169 MMcf of natural gas purchased in 2009, was associated with the Shongaloo Properties acquisition. The Predecessor did not purchase any reserves in place in 2008.
 
 Sale of Reserves in Place. In 2009, the Predecessor sold a portion of its non-core oil and gas properties in Alabama, Colorado, Louisiana, New Mexico and Texas representing approximately 8% of total production.
  F-43
 Table Of Contents
  Revisions of Previous Estimates. In 2009, the Predecessor had net positive revisions of 2,011 MBbl of oil and 1,760 MMcf of natural gas, primarily due to higher commodity prices in 2009 as compared to the prices at the end of 2008.
 
 In 2008, the Predecessor had net negative revisions of 13,312 MBbl of oil and 48,547 MMcf of natural gas. The reserves in the Jay Field were deemed uneconomic as of December 31, 2008. The volumes removed were 1,330 MBbl and 17,109 MMcf. The negative revisions were attributable to higher operating costs and lower prices for production.
 
 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 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 $74.52/Bbl for oil and $4.53/MMbtu for natural gas as of December 31, 2010; the unweighted arithmetic average first-day of-the-month prices for the prior 12 months were $61.18/Bbl for oil and $3.87/MMbtu for natural gas as of December 31, 2009; and the index prices were $41.00/Bbl for oil and $5.71/MMbtu for natural gas as of December 31, 2008. 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, 2010, the relevant average realized prices for oil, natural gas and NGLs were $ 85.58 per Bbl, $ 3.84 per Mcf and $ 60.42 per Bbl. As of December 31, 2009, the relevant average realized prices for oil, natural gas and NGLs were $56.46 per Bbl, $3.75 per Mcf and $33.12 per Bbl. The impact of the adoption of the FASB’s authoritative guidance on the SEC oil and gas reserve estimation final rule on our financial statements is not practicable to estimate due to the operation and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.
 
 Changes in the demand for oil and natural gas, inflation and other factors made such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of current market value of the proved reserves attributable to our reserves.
  F-44
 Table Of Contents
  The estimated standardized measure of discounted future net cash flows relating to our proved reserves is shown below for the periods indicated:
 
 Partnership



PredecessorDecember 31,



December 21,


December 31,


December 31,2010



2010 (1)


2009 (2)


2008Future cash inflows

$
1,772,323


$
4,019,453


$
707,028


$
519,797Future production and development costs


(737,789
)


(1,790,043
)


(319,391
)


(297,459
)Future net cash flows


1,034,534



2,229,410



387,637



222,33810% annual discount for estimated timing of cash flows


(536,122
)


(1,092,216
)


(170,762
)


(90,754
)Standardized measure of discounted future net cash flows

$
498,412


$
1,137,194


$
216,875


$
131,584
  (1)
This standardized measure of discounted cash flows includes $1,072.6 million attributable to an approximate 94.3% noncontrolling interest in the Predecessor as of December 21, 2010.
  (2)
This standardized measure of discounted cash flows includes $202.1 million attributable to an approximate 93.2% noncontrolling interest in the Predecessor as of December 31, 2009.
 The above table does not include the effects of income taxes on future net revenues because during 2010, 2009 and 2008, 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 and natural gas reserves for the periods indicated:
 
 Partnership


PredecessorDecember 22 to


January 1 toDecember 31,


December 21,


Year Ended December 31,2010


2010


2009


2008Beginning of period

$
-


$
216,875


$
131,584


$
778,820Contribution from Predecessor


500,487



-



-



-Purchases of reserves in place


-



836,500



51,202



-Sale of reserves in place


-



-



(10,106
)


-Revisions of previous estimates


-



77,585



33,930



(208,042
)Changes in future development cost, net


-



(50,731
)


3,149



75,446Development cost incurred during the year that reduce future development costs


-



1,882



1,853



9,921Net change in prices


-



73,352



51,552



(384,057
)Sales, net of production costs


(2,075
)


(150,403
)


(23,724
)


(127,756
)Changes in timing and other


-



110,446



(35,723
)


(90,630
)Accretion of discount


-



21,688



13,158



77,882End of period

$
498,412


$
1,137,194


$
216,875


$
131,584
  F-45
 Table Of Contents
 Predecessor share of Ute Energy, LLC
 
 The Predecessor has an investment in Ute that is accounted for under the equity method. The following disclosures represent the Predecessor’s share of Ute reserves and oil and gas operations.  Since we do not have sufficient information from Ute to present these disclosures as of December 21, 2010 and for the 355-day period then ended, these disclosures include the year-end balances and all activity for 2010.
 
 Capitalized Costs
 
 The following table summarizes the carrying value of our portion of Ute's consolidated oil and gas assets as of December 31, 2010 and 2009.
  December 31,2010


2009Proved properties

$
26,704


$
12,020Less: Accumulated depreciation,depletion, amortization and impairment


(7,187
)


(3,705
)Proved properties, net


19,517



8,315Unproved properties


1,067



268Total oil and gas properties, net

$
20,584


$
8,583
 Costs Incurred
 
 The following table sets forth our share of capitalized costs incurred in Ute's property acquisition, exploration and development activities for the years ended December 31, 2010 and 2009.
 
 Year endedDecember 31,2010


2009Development costs

$
14,631


$
2,787Asset retirement obligation


116



-Acquisitions


812



-Total costs incurred for acquisition and development activities

$
15,559


$
2,787
 Estimated Proved Reserves
 
 All of Ute's proved reserves are located entirely within the continental United States. Following is a summary of our share of the proved developed and total proved oil, natural gas and NGL reserves attributed to Ute's operations.
 
 As of December 31,2010


2009Oil


Gas


Oil


Gas(MBbl)


(MMcf)


(MBbl)


(MMcf)Proved reserves:Balance, beginning of period


1,003



2,603



227



900Recapitalization of Ute Energy, LLC


(140
)


(529
)


-



-Extensions, discoveries and other additions


1,117



2,552



281



660Divestiture of reserves


-



-



(1
)


(38
)Revisions of previous estimates


(124
)


(205
)


551



1,274Production


(123
)


(296
)


(55
)


(193
)Balance, end of period


1,733



4,125



1,003



2,603Proved developed reserves:End of period


611



1,686



283



1,078
  F-46
 Table Of Contents
 Standardized Measure of Discounted Future Net Cash Flows
 
 For the years ended December 31, 2010 and 2009, our share of Ute's future cash inflows are calculated by applying the current SEC 12-month average pricing of oil and gas relating to proved reserves to the year-end quantities of those reserves. For 2010, calculations were made using SEC prices of $67.87 per Bbl WTI index for oil, $3.82 per MMBtu Henry Hub index for gas and $56.40 per Bbl Mt. Belvieu index for NGLs. For 2009, calculations were made using SEC prices of $61.18 per Bbl WTI index for oil, $3.87 per MMBtu Henry Hub index for gas and $42.83 per Bbl Mt. Belvieu index for NGLs.
 
 The estimated standardized measure of discounted future net cash flows relating to our share of Ute's proved reserves is shown below:
  December 31,2010


2009Future cash inflows

$
132,914


$
57,291Future production costs


(59,674
)


(23,008
)Future development costs


(27,886
)


(15,711
)Future net cash flows


45,354



18,57210 percent annual discount


(18,530
)


(9,625
)Standardized measure of discounted future net cash flows

$
26,824


$
8,947
 A summary of changes in the standardized measure of discounted future net cash flows is as follows:
 
 Year endedDecember 31,2010


2009Standardized measure of discounted future net cash flows, beginning of period

$
8,947


$
3,514Recapitalization of Ute Energy, LLC


(1,916
)


-Sales of oil and gas, net of production costs and local taxes


(7,601
)


(1,340
)Extensions, discoveries and improved recoveries, less related costs


16,837



2,952Revisions of previous quantity estimates


(964
)


2,374Net changes in prices and production costs


5,196



192Previously estimated development costs incurred during the period


1,779



-Changes in estimated future development costs, net


1,344



210Development costs incurred during the year that reduce future development costs


-



106Sales of reserves in place


-



(65
)Change in production rates (timing) and other


2,499



653Accretion of discount


703



351Standardized measure of discounted future net cash flows, end of period

$
26,824


$
8,947
  F-47
 Table Of Contents
 SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
 
 Quarterly financial data was as follows for the periods indicated:
 
 Predecessor


PartnershipFirst


Second


Third


Fourth


FourthQuarter


Quarter


Quarter


Quarter(1)


Quarter(1)2010Revenues

$
35,633


$
55,359


$
84,478


$
77,916


$
3,014Gross profit


21,318



32,417



53,179



38,064



2,075Operating income


8,801



8,405



13,429



1,660



857Net income (loss)


9,176



43,291



(1,486
)


(19,068
)


(7,099
)
 2009Revenues

$
16,268


$
17,067


$
19,743


$
19,723


$
-Gross profit


6,752



6,841



7,831



6,536



-Operating Loss


(4,777
)


(33,344
)


(5,938
)


(6,994
)


-Net loss


(9,252
)


(67,297
)


(304
)


(38,561
)


-
 (1)
Fourth quarter 2010 results are split 82 days under Predecessor and 10 days under the Partnership to reflect the closing of IPO.
 
 
 F-48