10-K 1 form10k.htm QR ENERGY, LP 10-K 12-31-2011 form10k.htm
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, 2011

OR

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

Commission File Number 001-35010

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 þ   NO¨

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 þ   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 þ
   
Non-accelerated filer ¨
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, 2011, the last business day of the registrant’s most recently completed second fiscal quarter; the aggregate market value of the Common Units held by non-affiliates was approximately $356,252,000, based on the closing price of $20.64 per unit on that date. For purposes of this calculation, QA Holdings, LP, which owned 11,297,737 Common Units on such date, is considered an affiliate of the registrant.
 
As of March 15, 2012, the registrant had 16,666,667 Class C Convertible Preferred Units, 28,590,016 Common Units, 7,145,866 Subordinated Units and 35,729 General Partner Units outstanding. 
 
 
 
 
 
TABLE OF CONTENTS
 
PART I
     
Item 1.
9
Item 1A.
29
Item 1B.
59
Item 2.
59
Item 3.
59
Item 4.
59
     
PART II
     
Item 5.
60
Item 6.
63
Item 7.
67
Item 7A.
86
Item 8.
88
Item 9.
88
Item 9A.
89
Item 9B.
Other Information
81
     
PART III
     
Item 10.
97
Item 11.
103
Item 12.
   114
Item 13.
115
Item 14.
118
     
PART IV
     
Item 15.
119
     
121
 
GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

Bbl/d:  One Bbl per day.

Bcf:  One billion cubic feet of natural gas.

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

Boe/d:  One Boe per day.

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

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

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

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

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

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

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

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

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

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

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

 
 
·
provide improved recovery systems.

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

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

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

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

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

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

FASB:  Financial Accounting Standards Board

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

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

MBbls:  One thousand Bbls.

MBbls/d:  One thousand Bbls per day.

MBoe:  One thousand Boe.

MBoe/d:  One thousand Boe per day.

Mcf:  One thousand cubic feet of natural gas.

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

MMBoe:  One million Boe.

MMBtu:  One million British thermal units.

MMcf:  One thousand Mcf.

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

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

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


NGLs:  The combination of ethane, propane, butane and natural gasolines which, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
 
Novate: To substitute by mutual agreement one obligation for another, such as the substitution of one party to a contract for another, with the intent to extinguish the old obligation.  For example the substitution of one party to a derivative contract for another party upon mutual consent of the original counterparties and the concurrence of the new party.

NYMEX:  New York Mercantile Exchange.

Oil:  Oil and condensate.

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

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

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

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

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

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

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

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

SEC:  The US Securities and Exchange Commission.

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

Standardized measure:  The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the unweighted arithmetic average first-day of-the-month prices for the prior 12 months), less future development, production and income tax expenses and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.
 
 
Undeveloped acreage:  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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

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

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


NAMES OF ENTITIES

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

 
·
“QR Energy,” “the Partnership,” the "Company" “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 general partner of the Partnership;

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

 
·
the “Predecessor” refers to QA Holdings, LP, our predecessor for accounting purposes and the indirect owner of the general partner interests of the 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 $893.0 million of oil and natural gas properties, which we refer to as the “Denbury Assets,” from Denbury Resources Inc. in May 2010.

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

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

FORWARD–LOOKING STATEMENTS

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

 
·
business strategies;

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

 
·
drilling locations;

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

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

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

 
·
uncertainty inherent in estimating our reserves;

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

 
·
cash flows and liquidity;

 
·
potential shortages of drilling and production equipment;

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

 
 
·
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 Form 10-K. All forward-looking statements speak only as of the date of this report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.


PART I

ITEM 1. BUSINESS

Overview
 
QR Energy, LP is a Delaware limited partnership formed in September 2010 by affiliates of 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. We acquired a portion of our assets from the Fund in connection with our initial public offering (“IPO”) completed on December 22, 2010 which included oil and gas producing properties located in Alabama, Arkansas, Kansas, Louisiana, New Mexico, Oklahoma and Texas and an overriding royalty interest in Florida. Effective, October 1, 2011, we acquired the Transferred Properties from the Fund located in the Permian Basin, Ark-La-Tex, and MidContinent areas.

Our properties consist of mature, legacy onshore oil and natural gas reservoirs with long-lived, predictable production profiles. As of December 31, 2011, our total estimated proved reserves were approximately 75.2 MMBoe, of which approximately 56% were oil and NGLs and 68% were classified as proved developed reserves. As of December 31, 2011, our estimated proved reserves had a standardized measure of $1.2 billion. As of December 31, 2011, we produced from 3,867 gross (1,631 net) producing wells across our properties, with an average working interest of 42%.
 
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, 2011 and our average net production for the year ended December 31, 2011:

   
Estimated Net Proved Reserves
     Production        
   
Oil &
          
Natural
          
Standardized (1)
   
Average Net Production (2)
          
 
  
   
Cond.
    
NGLs
     Gas          
Measure
         
% of
   
%
   
Producing Wells
  
   
(MBbls)
    
(MBbls)
    
(MMcf)
    
MBoe
    
($ millions)
    
Boe/d
    
Total
    
Liquids
    
Gross
    
Net
  
Permian Basin
     27,410.4       2,963.0       42,105.0       37,390.9     $ 748.7       7,218       51%       54%       2,785       985  
Ark-La-Tex
     2,891.8       4,526.1       129,962.0       29,078.2       243.9       4,706       34%       23%       666       437  
Mid-Continent
     3,017.8       193.4       21,058.7       6,721.0       111.6       1,509       11%       45%       400       205  
Gulf Coast
     929.7       161.3       5,428.4       1,995.7       68.3       514       4%       72%       16       4  
Total
     34,249.7       7,843.8       198,554.1       75,185.8     $ 1,172.5       13,947       100%       43%       3,867       1,631  

 
(1)
As of December 31, 2011 our standardized measure of discounted future net cash flows was $1.2  billion.  Because we are a limited partnership, we are generally not subject to federal or state income tax and thus make no provision for federal or state income taxes in the calculation of our standardized measure.
 
(2)
Production data includes all 2011 volumes and wells of the Transferred Properties acquired under common control in October 2011 and have been revised as if the Partnership owned the assets as of the beginning of the year.

Recent Developments

On October 3, 2011 we completed the acquisition of the Transferred Properties including certain oil and gas properties located in the Permian Basin, Ark-La-Tex and Mid-Continent areas from the Fund pursuant to a Purchase and Sale Agreement (the “Purchase Agreement”) with an effective date of October 1, 2011.

In exchange for the Transferred Properties, we assumed $227.0 million in debt from the Fund, which was repaid at closing and issued to the Fund 16,666,667 unregistered Class C Convertible Preferred Units (“Preferred Units”). The Preferred Units will receive a preferred quarterly distribution of $0.21 per Preferred Unit equal to a 4.0% annual coupon on the par value of $21.00, for the first three years following the date of issuance. After three years, the quarterly cash distribution will be equal to the greater of (a) $0.475 per Preferred Unit or (b) the cash distribution payable on each of our common units for such quarter. The Preferred Units are convertible, subject to certain limitations, into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment.


In connection with the issuance of the Preferred Units, we amended our First Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) to designate and create the Preferred Units and set forth the rights, preferences and privileges of such units, including the respective conversion rights held by the holders of the Preferred Units and us.

In connection with the acquisition of the Transferred Properties, we amended our credit facility on October 3, 2011 to increase the borrowing base by $300.0 million. We borrowed $234.0 million under the credit facility to repay $227.0 million of debt we assumed from the Fund in connection with the Purchase Agreement and paid approximately $2.1 million in transaction fees and utilized the remaining $4.7 million for working capital needs.

On October 4, 2011, the board of directors of QRE GP declared a quarterly distribution of $0.475 per unit, or $1.90 on an annualized basis, for the fourth quarter of 2011 for all outstanding units. This quarterly distribution as well as the $0.21 per unit distribution on preferred units were included in the cash distributions of $20.5 million paid on February 20, 2012 to all unitholders of record at the close of business on January 30, 2012.

Presentation

Because these Transferred Properties were acquired from the Predecessor, the acquisition was accounted for as a transaction between entities under common control, whereby the Partnership’s accompanying consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” have been revised for the period from December 22, 2010 to December 31, 2010 and the portion of 2011 prior to the October 1, 2011 effective date of the acquisition, similar to a pooling of interests, to include the financial position, results of operations, and cash flows of the net assets attributable to the Transferred Properties. See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information on the Partnership’s accounting presentation.


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.

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; 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, 2011, the Fund had total estimated proved reserves of 17.6 MMBoe, of which approximately 90%  were proved developed reserves, with standardized measure of $389.8 million, and interests in more than 189 gross (147 net) oil and natural gas wells. After the sale of the Transferred Properties to us effective October 1, 2011, the Fund’s remaining properties had average net production of approximately 5,795 Boe/d  for the three months ended December 31, 2011. The estimates of proved reserves owned by the Fund as of December 31, 2011 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 84% of the Fund’s estimated reserves are classified as proved developed producing, based on the Fund’s December 31, 2011 third-party reserve report. Additionally, we believe the percentage of the Fund’s estimated reserves classified as proved developed producing will increase over time as the Fund invests its capital to convert its undeveloped properties to proved developed producing. It is difficult to predict which properties the Fund may offer for sale in future periods or the reserve classifications of any such properties. As a result, we are unable to quantify the number of potential sale transactions that may meet the 70% proved developed producing reserve criteria.

The Fund will determine whether any group of properties offered for sale meets the 70% threshold, and therefore, whether it is obligated to offer such properties to us. The 70% threshold is a value-weighted determination made by the Fund, acting in good faith pursuant to the terms of our omnibus agreement, and is subject to a number of subjective assumptions. As such, other than the Fund’s obligation to act in good faith, there are no additional safeguards in place to prevent the Fund from selecting a subset of assets that do not meet this standard or allocating value in a manner where the proved developed producing assets are below the 70% threshold. Given the Fund’s significant ownership in us, 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 allow us to participate in its acquisition opportunities to the extent that it invests any of the remaining approximately $193.2 million of its unfunded committed equity capital. Specifically, the Fund will 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 agreed, 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 the Fund has a vested interest in our ability to increase our reserves and production since it holds an aggregate 67% limited partner interest in us including 11,297,737 of our common units and all of our preferred and subordinated units as of March 15, 2012. 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.

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.


Our Areas of Operation

On December 22, 2010, Quantum Resource Funds contributed to us certain fields (IPO Assets) 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. Additionally, effective October 1, 2011, Quantum Resource Funds contributed to us additional fields (Transferred Properties) in the same areas. The Partnership’s operating results for the period from December 22, 2010 to December 31, 2010 and the year ended December 31, 2011 have been revised to include the results of the Transferred Properties as if the Partnership owned the properties during both of these periods.
 
Our 2010 and 2009 operating results for average net production, average sales price by product and average costs by, geographic region, and any significant fields, is not presented as we had only 10 days of operations from December 22, 2010 to December 31, 2010 and are not comparable with our current results.
 
The table below summarizes our average net production, average sales prices by product and average production costs for the year ended December 31, 2011 and our reserves by geographic region as of December 31, 2011:

   
Permian
    
Ark-La-Tex
    
Mid-Continent
    
Gulf Coast
    
Total
  
Production:
                              
Oil (MBbl)
     1,220       185       238       123       1,766  
Gas (Mmcf)
     7,282       7,984       1,811       309       17,386  
NGL (MBbl)
     201       202       11       13       427  
Mboe
     2,635       1,718       551       187       5,091  
Boe/d
     7,218       4,706       1,509       514       13,947  
                                         
Average sales price per unit:
                                        
Oil (per Bbl)
   $ 90.74     $ 93.48     $ 91.78     $ 104.15     $ 92.10  
Natural gas (per Mcf)
   $ 5.53     $ 4.07     $ 5.31     $ 4.39     $ 4.80  
Natural gas liquids (per Bbl)
   $ 49.67     $ 55.08     $ 46.73     $ 66.38     $ 53.30  
                                         
Lease operating expense (per Boe):
   $ 15.10     $ 9.45     $ 16.61     $ 13.72     $ 13.06  
                                         
Reserves:
                                        
MBoe
     37,390.9       29,078.2       6,721.0       1,995.7       75,185.8  
% Liquids
     81%       26%       48%       55%       56%  
% Proved Developed
     66%       62%       99%       99%       68%  
% of Proved Operated
     73%       99%       78%       46%       83%  
% of Total Proved
     50%       39%       9%       2%       100%  
                                         
% of 2012 Capital Budget:
     70.1%       25.2%       2.5%       2.2%       100.0%  
 

Permian Basin

The Permian Basin area includes properties located in west Texas and southeast New Mexico and produces from a variety of reservoirs such as the San Andres, Grayburg and Clearfork formations at depths ranging from 4,000 to 11,000 feet.  Many of these properties are under secondary recovery waterflood operations. During 2012, we expect to invest capital in the Permian Basin, primarily on infill drilling and well work in preparation for waterflood expansion.

The Fuhrman Field is a significant field which constituted approximately 15 % of our estimated proved reserves as of December 31, 2011.  The Partnership’s production from the Fuhrman Field is presented in the table below for the year ended December 31, 2011.

   
2011
  
Production:
      
Oil (MBbl)
     288  
Gas (Mmcf)
     86  
NGL (MBbl)
     2  
Mboe
     304  
Boe/d
     834  

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. During 2012, we expect to invest capital in the Ark-La-Tex area, primarily on recompletions and artificial lift implementation.


The Overton Field is a significant field which constituted approximately 15% of our estimated proved reserves as of December 31, 2011. The Partnership’s production from the Overton Field is presented in the table below for the year ended December 31, 2011.
 
   
2011
  
Production:
      
Oil (MBbl)
     20  
Gas (Mmcf)
     1,737  
NGL (MBbl)
     1  
Mboe
     310  
Boe/d
     849  

Mid-Continent

The Mid-Continent area includes properties located in Oklahoma, southwestern Kansas and the Texas panhandle.  These properties produce from formations such as the Cottage Grove Sand, Atoka, Redfork and Lansing at depths ranging from 6,000 to 15,000 feet. During 2012, we expect to invest capital in the Mid-Continent area, primarily on recompletions and workovers.

Gulf Coast

The Gulf Coast area includes properties located in southern Alabama and southeast Texas. We also own a net 7.44% 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. During 2012, we expect to invest capital 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. Our reserve estimates are prepared 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 25 years of industry experience with positions of increasing responsibility in reservoir engineering and reserves evaluation with Santa Fe Minerals, Murphy Exploration & Production, Pioneer Natural Resources, and Denbury Resources. The Senior Reservoir Engineer holds a Bachelor of Science in Petroleum Engineering.

Miller & Lents. Miller & Lents, Ltd. is an independent oil and natural gas consulting firm. No director, officer, or key employee of Miller & Lents, Ltd. has any financial ownership in 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 overseen by the firm’s Vice President who is an experienced reservoir engineer having been a practicing petroleum engineer since June of 1981. He has more than 20 years of experience in reserves evaluation. He holds a Bachelors of Science Degree in Chemical Engineering and is a registered professional engineer in Texas.

Estimated Proved Reserves. The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2011 based on reserve reports prepared by Miller & Lents, Ltd.. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.

   
Oil &
Cond.
(MBbls)
    
NGLs
(MBbls)
    
Natural
Gas
(MMcf)
    
MBoe
    
Standardized
Measure
($ Thousands)
  
Permian:
                              
Developed
     15,482       2,798       38,574       24,709     $ 482,694  
Undeveloped
     11,929       165       3,531       12,682       266,034  
Total
     27,411       2,963       42,105       37,391     $ 748,728  
                                         
Ark-La-Tex
                                        
Developed
     2,093       2,929       77,389       17,920     $ 192,956  
Undeveloped
     799       1,597       52,573       11,158       50,919  
Total
     2,892       4,526       129,962       29,078     $ 243,875  
                                         
Mid-Continent
                                        
Developed
     2,971       193       21,036       6,670     $ 105,335  
Undeveloped
     47       -       23       51       6,264  
Total
     3,018       193       21,059       6,721     $ 111,599  
                                         
Gulf Coast
                                        
Developed
     912       161       5,428       1,978     $ 67,001  
Undeveloped
     18       -       -       18       1,338  
Total
     930       161       5,428       1,996     $ 68,339  
                                         
Total
                                        
Developed
     21,458       6,081       142,427       51,277     $ 847,986  
Undeveloped
     12,793       1,762       56,127       23,909       324,555  
Total
     34,251       7,843       198,554       75,186     $ 1,172,541  
 

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 SEC and FASB guidance, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Production, Revenue and Price History

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

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

We currently have 449 undeveloped locations. All of our PUD locations are adjacent to existing productive wells. Therefore, the reservoir risk is lower than PUDs associated with step out or field extensions.
 
We assess our PUD reserves on a semiannual basis. At December 31, 2011, we had 23,909 MBoe of consolidated PUD reserves representing an increase of 392 MBoe of PUD reserves compared to December 31, 2010 as revised based on our acquisition of the Transferred Properties as a transaction between entities under common control. During 2011, we added 1,497 MBoe of PUD reserves primarily due to our drilling activities in the Grayburg-San Andres, Penn-Wolf and Cotton Valley formations in our Permian and Ark-La-Tex areas.

We spent approximately $16.2 million, during 2011 to convert approximately 5% or 1.1 MBoe of our prior year-end PUD reserves to proved developed reserves. In our December 31, 2011 reserve report, the amounts estimated to be spent over the next five years to develop our consolidated PUD reserves are $309.2 million or an average of $61.8 million per year. The amounts estimated to be spent to develop our PUD reserves is a result of our capital focus to develop our core projects. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and commodity prices.

Of the 23,909 MBoe of PUD reserves at December 31, 2011, we have 203 MBoe ($3.2 million based on standardized measure) of undeveloped reserves that are outside of our current five-year development plan. These projects comprise an aggregate of 79 properties in the Grayburg-San Andres formation in the Permian area and are not material to our overall total proved or total PUD reserves as of December 31, 2011. On an MBoe basis the properties comprised 0.3% of our total proved reserves and 0.8% of our total PUD reserves as of December 31, 2011. On a standardized measure basis, the properties comprised 0.3% of our total proved reserves and 1.0% of our total PUD reserves as of December 31, 2011.
 
 
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, 2011.

   
Oil
    
Natural Gas
  
   
Gross
    
Net
    
Gross
    
Net
  
Operated
     1,043       985       709       508  
Non-operated
     1,812       54       303       84  
Total
     2,855       1,039       1,012       592  

Developed Acreage

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2011, all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2011 relating to our leasehold acreage.

   
Developed Acreage
  
   
Gross
    
Net
  
Permian Basin
     85,532       59,484  
Ark-La-Tex
     76,848       50,133  
Mid-Continent
     112,649       57,588  
Gulf Coast
     2,575       1,566  
Total
     277,604       168,771  

Title to Properties

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

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

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

 
Drilling Activities

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

   
Year Ended December 31,
  
               
Predecessor
  
   
2011 (1)
    
2010 (2)
    
2009
  
   
Gross
    
Net
    
Gross
    
Net
    
Gross
    
Net
  
Productive
    88     11       72       4       123       3  
Dry
     -       -       -       -       -       -  
Total
     88       11       72       4       123       3  


 
(1)
As of December 31, 2011 we had 1 gross (1 net) development well in the Permian Basin that was in the completion stages for  integration into operations.
 
(2)
During 2010, we have made no allocation of drilling activity for the 10-day period from December 22, 2010 through December 31, 2010 between us and the Predecessor, as the drilling activity for this period allocable is inconsequential.

Current Activities

As of December 31, 2011, we had enhanced recovery operations ongoing in the Gulf Coast, Mid Continent, and Permian Basin regions with one well in process of completion as indicated in Drilling Activities above.

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, 2011. We design and manage the development, recompletion or workover for all of the wells we operate including the supervision of operation and maintenance activities. We do not own the drilling rigs or other oil field services equipment used for drilling or maintaining wells on the properties we operate. Independent contractors provide all the equipment and personnel associated with these activities. Pursuant to our general partner’s services agreement, Quantum Resources Management provides certain administrative services to us. Quantum Resources Management employs production and reservoir engineers, geologists and other specialists, as well as field personnel. 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 which 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 year ended December 31, 2011 was $2.5 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”.

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 66%, resulting in a net revenue interest to us ranging from 34% to 100%, or 80.4% on average. As of December 31, 2011, all of our leases are held by production except as to 409 gross acres and 404 net acres.

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
    
Predecessor
  
   
2011(1)
    
2010(1)
    
2010
    
2009
  
ConocoPhillips
     16%       13%        (2)       (2)  
Plains Marketing LP
     13%       14%        (2)       10%  
Shell Trading US Company
     (2)       12%       45%       24%  
Sunoco Inc R&M
     (2       10%       10%       12%  
ExxonMobil Corporation
     17%       11%        (2)       (2)  


 
(1)
In 2011 and 2010 these percentages are reflective as if the Partnership owned all acquired properties for the entire year.
 
(2)
These customers accounted for less than 10% of total revenues for the periods indicated.

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

If we were to lose any one of our customers, the loss could temporarily delay production and sale of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether, the loss 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. Our current commodity derivative contracts include fixed price swaps and collars on future oil production with WTI prices, fixed price swaps and basis swaps on future natural gas production with NYMEX prices and collars on future natural gas production with Henry Hub prices.


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

Competition

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

Seasonal Nature of Business

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

Environmental and Occupational Safety and Health Matters

General

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

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

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

Hazardous Substances and Wastes

The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the U.S. Environmental Protection Agency, or EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For instance, in September 2010, the Natural Resources Defense Council filed a petition for rulemaking with the EPA requesting reconsideration of the continued application of this RCRA exclusion but, to date, the EPA has not taken any action on the petition.  A loss of this exclusion could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position.

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 recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or 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 state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure, or SPCC, plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a 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.

 
Hydraulic Fracturing
 
Hydraulic fracturing is an important and common industry practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.  Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel.  In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process.  At the state level, some states, including Louisiana and Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing activities.  We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nevertheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices.  The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

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

Air Emissions

The federal Clean Air Act, as amended, and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.  For example, on July 28, 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production, including, among other things, the application of reduced emission completion techniques, referred to as “green completions,” for completion of newly drilled and fractured wells in addition to establishing specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment.  Final action on the proposed rules is expected no later than April 3, 2012.  If this action is finalized, we do not believe that such requirements will have a material adverse effect on our operations.

 
Climate Change

Based on findings made by the EPA in December 2009 that emissions of carbon dioxide, or CO2, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires reductions in emissions of GHGs from motor vehicles and another one that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources.  The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities, which include the majority of our operations on an annual basis. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

In addition, the U.S. Congress has, from time to time, considered legislation to reduce emissions of GHGs, and almost one-half of 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.  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.

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 ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required.  Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA over the next six years, through the agency’s 2017 fiscal year.  The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.


OSHA

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

Other Regulation of the Oil and Natural Gas Industry

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

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

Drilling and Production

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

 
·
the location of wells;

 
·
the method of drilling and casing wells;

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

 
·
the plugging and abandoning of wells; and

 
·
notice to surface owners and other third parties.

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

 
Natural Gas Regulation

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

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

State Regulation

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

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

Employees
 
The officers of our general partner manage our operations and activities. However, neither we, our subsidiaries, nor our general partner have employees. Our general partner has entered into a services agreement with Quantum Resources Management pursuant to which Quantum Resources Management performs services for us, including the operation of our properties. See “Item 13. Certain Relationships and Related Transactions, and Director Independence — Services Agreement.”
 
As of December 31, 2011, Quantum Resources Management had 250 employees, including 19 engineers, 2 geologists and 17 land professionals. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that Quantum Resources Management’s relations with its employees are satisfactory. We will also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, finance and other disciplines as needed.


Offices

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

Available Information

Our annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our website at www.qrenergylp.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. These documents are also available on the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. Our website also includes our Code of Business Conduct, our Corporate Governance Guidelines 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.
 

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;

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

 
·
interest payments;

 
·
fluctuations in our working capital needs;


 
·
general and administrative expenses; and

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

As a result of these factors, the amount of cash we distribute to our unitholders may fluctuate significantly from quarter to quarter and may be less than the 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.”

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

The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices.  For example, market prices for natural gas in the United States have declined substantially from 2008 price levels, and the rapid development of shale plays throughout North America has contributed significantly to this trend. Lower prices also may reduce the amount of natural gas or oil that we can produce economically. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

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

 
·
weather conditions and the occurrence of natural disasters;

 
·
overall domestic and global economic conditions;

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

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

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

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

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

 
·
domestic and foreign governmental regulations and taxation;

 
·
the impact of energy conservation efforts;

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

 
·
the availability of refining capacity; and

 
·
the price and availability of alternative fuels.

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during 2011, the NYMEX–WTI oil price ranged from a high of $113.39 per Bbl to a low of $75.40 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $4.92 per MMBtu to a low of $2.84 per MMBtu. For the five years ended December 31, 2011, the NYMEX–WTI oil price ranged from a high of $145.31 per Bbl to a low of $30.28 per Bbl, while the NYMEX–Henry Hub natural gas price ranged from a high of $13.31 per MMBtu to a low of $1.83 per MMBtu. Natural gas prices have experienced a continuous decrease in late 2011 and early 2012. Future decreases in the natural gas market price could have a negative impact on revenues, profitability, and cash flow. Declines in future natural gas market prices could also have a negative impact on our reserves values. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. – Critical Accounting Policies and Estimates”


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:

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

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

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

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

 
·
impair our ability to pay distributions to our unitholders.

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

Our estimated oil and natural gas reserves will naturally decline over time, and it is unlikely that we will be able to sustain distributions at the level of our minimum quarterly distribution without making accretive acquisitions or substantial capital expenditures that maintain our asset base.

Our future oil and natural gas reserves, production volumes, cash flow and ability to make distributions to our unitholders depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. Based on our December 31, 2011 reserve report, the average decline rate for our existing proved developed producing reserves is approximately 12% for 2012, approximately 7% 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 $50.0 million will enable us to maintain the current level of production from our assets through December 31, 2016. 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 our new credit facility and the issuance of debt and equity securities.

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

 
·
our estimated proved oil and natural gas reserves;

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

 
·
the prices at which we sell our production;

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

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

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

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

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

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

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

The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating derivative positions. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price we receive could significantly reduce our cash available for distribution to our unitholders and adversely affect our financial condition. In 2011 we entered into basis differential derivative contracts to reduce the impact of these differentials in respect of our production.  The prices as which we enter into basis differential derivative contracts in the future will be dependent upon price differentials at the time we enter into these transactions, which may be substantially higher or lower than the current differentials.  Accordingly, our differential hedging strategy may not protect us from significant increases in price differentials.


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

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

We utilize the full cost method of accounting for oil and natural gas exploration and development activities. Under this method, all costs associated with property exploration and development (including costs of surrendered and abandoned leaseholds, 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, 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. In accordance with our risk management policy, for 2012, and over a three-to-five year period at a given point in time, approximately 15% to 35% of our estimated total oil and natural gas production will not be covered by commodity derivative contracts. In addition, none of our estimated total NGL production is covered by commodity derivative contracts. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

We have adopted a hedging policy to reduce the impact to our cash flows from commodity price volatility.  In 2011, we entered into basis differential derivative contracts to reduce the impact of differentials we experience in respect of our production. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our 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 and differential derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so. However, our price hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under an obligation to enter into commodity and differential derivative contracts covering a specific portion of our production. The prices at which we enter into commodity and differential derivative contracts covering our production in the future will be dependent upon oil and natural gas prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.


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

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

Our hedging transactions expose us to counterparty credit risk.

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

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

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

 
·
the level of oil and natural gas prices;

 
·
future production levels;

 
·
capital expenditures;

 
·
operating and development costs;

 
·
the effects of regulation;

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


 
·
the availability of funds.

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our estimated proved reserves could change significantly. For example, if the prices used in our December 31, 2011 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 $260.6 million, from $1.2 billion to $911.9  million.

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

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

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

We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect as of the date of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

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

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

 
·
the amount and timing of actual production;

 
·
the amount and timing of our capital expenditures;

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

 
·
changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with by SEC and FASB guidance, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Secondary and tertiary recovery techniques may not be successful, which could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Approximately 24% of our 2011 production and 33% of our estimated proved reserves as of December 31, 2011 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

 
·
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 the deterioration of our facilities and equipment due to the highly corrosive nature of sour gas;

 
·
title problems;

 
·
pipe or cement failures and casing collapses;

 
·
compliance with environmental and other governmental requirements;

 
·
environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, discharges of toxic gases or other pollutants into the surface and subsurface environment;

 
·
lost or damaged oilfield development and service tools;

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

 
·
loss of drilling fluid circulation;

 
·
fires, blowouts, surface craterings and explosions;

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

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

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

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

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

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

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

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

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

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

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

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

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

 
·
outbid by competitors.

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


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

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

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

 
·
an inability to successfully integrate the businesses we acquire;

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

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

 
·
the assumption of unknown liabilities, losses or costs 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.


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 $500.0 million of debt outstanding as of December 31, 2011. We have the ability to incur debt, including under our credit facility, subject to anticipated borrowing base limitations in our credit facility. The level of our future indebtedness could have important consequences to us, including:

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

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

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

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

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

Our credit facility 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 90 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. These borrowing base redeterminations are based on an engineering report with respect to our estimated natural gas, NGL and oil reserves, which will take into account the prevailing natural gas, NGL and oil prices at such time, as adjusted for the impact of our commodity derivative contracts. In the future, we may be unable to access sufficient capital under our credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

A future decline in commodity prices could result in a redetermination that lowers our borrowing base 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.


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, 2011, 12.9 MMBoe of our estimated proved reserves and 1.0 MMBoe of our estimated proved undeveloped reserves, or 17% of our estimated proved reserves and 4% of our estimated proved undeveloped reserves as determined by volume and by value based on standardized measure, were attributable to properties for which we were not the operator. As a result, the success and timing of drilling and development activities on such nonoperated properties depend upon a number of factors, including:

 
·
the nature and timing of drilling and operational activities;

 
·
the timing and amount of capital expenditures;


 
·
the operators’ expertise and financial resources;

 
·
the approval of other participants in such properties; and

 
·
the selection and application of suitable technology.

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

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas exploration, production and processing operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production and processing of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. See “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, including one that requires a reduction in emissions of GHGs from motor vehicles and another one that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources.  The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore and offshore oil and natural gas production facilities, which may include certain of our operations, on an annual basis.

In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of 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. 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 GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.  See “Item 1. Business — Environmental and Occupational Safety and Health Matters.”


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

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

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


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

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders. See “Item 1. Business — Environmental and Occupational Safety and Health Matters” and “— Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect the third parties on whom we rely.

The adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative contracts to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress in 2010 adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010, and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate implementation rules and regulations within 360 days from the date of enactment. In December 2011, the CFTC extended temporary exemptive relief from regulations on certain provisions of the Act applicable to swaps until no later than July 16, 2012.  In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents.  Certain bona fide hedging transactions or positions would be exempt from these position limits.  It is not possible at this time to predict when the CFTC will make these regulations effective. 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 into a separate entity, which may not be as creditworthy as the current counterparty. The Act and any implementing regulations could significantly increase the cost of derivative contracts (including 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 in the completion of oil and natural gas wells.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.  Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel.  In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process.  At the state level, some states, including Louisiana and Texas, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing activities.  In the event new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

 
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.  The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices.  The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014.  Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

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.

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

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

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

 
Risks Inherent in an Investment in Us

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

 
·
as of March 15, 2012, the Fund owned a 67.0% limited partner interest in us including preferred, common and subordinated units. In addition, the general partner of the Fund is owned 72% by an entity controlled by Messrs Neugebauer, Van Loh, Smith and Campbell;

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

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

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

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

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

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

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


 
·
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.”

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, factors which may make it more difficult for us to compete with the Fund and Quantum Energy Partners with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. See “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. Should Quantum Energy Partners form other funds, Quantum Resources Management may enter into similar arrangements with those new funds. Because Quantum Resources Management provides services to us that are substantially similar to those provided to the Fund and, potentially, other funds, Quantum Resources Management may not have sufficient human, technical and other resources to provide those services at a level that Quantum Resources Management would be able to provide to us if it did not provide those similar services to the Fund and those other funds. Additionally, Quantum Resources Management may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of the Fund or other funds. There is no requirement that Quantum Resources Management favor us over the Fund or other funds in providing its services. If the employees of Quantum Resources Management and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

We have identified material weaknesses in our internal controls

Our management has concluded that our disclosure and procedures and internal control over financial reporting were not effective as of December 31, 2011.  Ineffective internal control over financial reporting could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading of our common units.  A description of the material weaknesses in our internal control over financial reporting is included in Part II, Item 9A. “Controls and Procedures” in this Report on Form 10-K.

The management incentive fee we 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.

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.”

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 2011, 3.5% of our Adjusted EBITDA, calculated prior to the payment of the fee, was $2.5 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.

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 67.0% limited partner interest in us as of March 15, 2012, 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;

 
·
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 ⅔% of all outstanding units voting together as a single class is required to remove our general partner. As of March 15, 2012, affiliates of the Fund and Quantum Energy Partners own our general partner and, through ownership of the general partner of the Fund, own a 67.0% 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.

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

Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. For example, in October 2011, we completed an acquisition of oil and natural gas properties from the Fund and issued preferred units as a portion of the transaction consideration that rank prior to our common units as to distributions upon liquidation.  These preferred units are convertible into common units upon the achievement of certain common unit trading price criteria prior to the second anniversary of their issuance, and are convertible without having to satisfy any such criteria following the second anniversary of their issuance. See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” information on the terms of our preferred units.

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

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

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

 
·
the ratio of taxable income to distributions may increase;

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

 
·
the market price of our common units may decline.


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

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

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

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

If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is the greater of (i) the highest cash price paid by either of our general partner or any of its affiliates for any common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those common units; and (ii) the average daily closing prices of our common units over the 20 days preceding the date three days before the date the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. As of March 15, 2012, the Fund owned a 67% limited partner interest in us including preferred, 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, and our preferred units may be converted into common units upon the achievement of certain common unit trading price criteria prior to the second anniversary of their issuance, and are convertible without having to satisfy any such criteria following the second anniversary of their issuance.  See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” information on the terms of our preferred units.

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.


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 for federal income tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

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

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

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


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

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

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

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

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

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

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

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

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


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

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

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

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

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

Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts, or IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be 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 depreciation, depletion, and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The 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.


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, 2011.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.


PART II

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

Our common units are listed and traded on the NYSE under the symbol “QRE.” As of the close of business on March 15, 2012, based upon information received from our transfer agent and brokers and nominees, we had 14 common unitholders of record. This number does not include owners for whom common units may be held in “street” names. The table below represents the daily high and low sales prices per common unit for the period from December 22, 2010 through December 31, 2010 and the year ended December 31, 2011.

   
Common Unit Price Range
  
   
High
    
Low
  
2011
            
October 1 - December 31
   $ 21.43     $ 17.81  
July 1 - September 30
   $ 21.80     $ 15.61  
April 1 - June 30
   $ 22.98     $ 19.93  
January 1 - March 31
   $ 23.56     $ 19.71  
2010
                
December 22 - December 31
   $ 21.50     $ 19.93  


We have also issued 16,666,667 Preferred Units and 7,145,866 subordinated units, for which there is no established public trading market. The preferred and subordinated units are held by affiliates of the Fund.
 
Preferred Units

In exchange for the Transferred Properties, we assumed $227.0 million in debt from the Fund, which was repaid at closing, and issued to the Fund 16,666,667 unregistered Class C Convertible Preferred Units. The Preferred Units will receive a preferred quarterly distribution of $0.21 per Preferred Unit equal to a 4.0% annual coupon on the par value of $21.00, for the first three years following the date of issuance. After three years, the quarterly cash distribution will be equal to the greater of (a) $0.475 per Preferred Unit or (b) the cash distribution payable on each of our common units for such quarter. The Preferred Units are convertible, subject to certain limitations, into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment
 
Holders may convert the Preferred Units to common units on a one-to-one basis prior to October 3, 2013, 30 consecutive trading days during which the volume-weighted average price for our common units equals or exceeds $27.30 per common unit. In addition, holders may convert the Preferred Units to common units on a one-to-one basis anytime on or after October 3, 2013.

If the holders have not converted the Preferred Units to common units by October 3, 2014, we may force conversion on a one-to-one basis, provided that conversion is in the 30 calendar days following 30 consecutive trading days during which the volume-weighted average price for common units equals or exceeds (1) $30.03, provided that (a) an effective shelf registration statement covering resales for the converted units is in place or (2) $27.30, provided that (a) above is satisfied and (b) there exists an arrangement for one or more investment banks to underwrite the converted unit sale following conversion (with proceeds equal to not less than $27.30 less (i) a standard underwriting discount and (ii) a customary discount not to exceed 5% of $27.30).

We may force conversion on a one-to-one basis after October 3, 2016, provided the conversion is in the 30 calendar days following 30 consecutive trading days during which the volume-weighted average price for common units equals or exceeds $27.30 and an effective shelf registration statement covering resales for the converted units is in place.
 
These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.
 
Cash Distributions to Unitholders

                         
Limited Partners
              
   
For the
  
Distributions to
    
Distributions per
    
General
    
Public
    
Affiliated
    
Total Distributions
    
Distributions
  
Date Paid
  
 period ended
  
Preferred Unitholders
    
Preferred Unit (1)
    
Partner
    
Common
    
Common
    
Subordinated
    
to Other Unitholders (2) (3)
    
per other units (2) (3)
  
(In thousands, except per unit amounts)
  
February 11, 2011
  
December 31, 2010
   $ -     $ -     $ 2     $ 779     $ 506     $ 320     $ 1,607     $ 0.0448  
May 13, 2011
  
March 31, 2011
     -       -       15       7,186       4,660       2,948       14,809       0.4125  
August 12, 2011
  
June 30, 2011
     -       -       15       7,184       4,660       2,948       14,807       0.4125  
November 11, 2011
  
September 30, 2011
     -       -       15       7,180       4,660       2,948       14,803       0.4125  
February 10, 2012
  
December 31, 2011
     3,424       0.2054       16       8,344       5,368       3,393       17,121       0.4750  
 
 
(1)
Preferred Units were prorated a quarterly distribution for the portion of the fourth quarter beginning on October 3, 2011 through December 31, 2011 in accordance with the Partnership Agreement.
 
(2)
The first quarter 2011 minimum quarterly distribution was prorated for the 10 day period from December 22, 2010 to December 31, 2010 in accordance with the Partnership Agreement.
 
(3)
An increase in the distribution rate of $0.475 was declared by the board of directors on October 3, 2011 and accrued in the fourth quarter 2011.

Common Unit Distributions. On October 4, 2011, the board of directors of Quantum Resources Management declared a quarterly cash distribution for the fourth quarter of 2011 of $0.475 per common and subordinated unit. The aggregate distribution of $17.1 million was paid on February 10, 2012 to common and subordinated unitholders of record as of the close of business on January 30, 2012. 


Preferred Unit Distribution. For the period beginning on October 3, 2011 and ending on December 31, 2014, we will distribute $0.21 per Preferred Unit on a quarterly basis.  Beginning on January 1, 2015, distributions on Preferred Units will be the greater of $0.475 per Preferred Unit or the distribution payable on common units with respect to such quarter.  As of December 31, 2011 we have accrued a fourth quarter distribution payable of $3.4 million to Preferred Unit holders that was paid on February 10, 2012.

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

Cash Distribution Policy

Our partnership agreement requires that within 45 days after the end of each quarter, we distribute all of our available cash to preferred unitholders, in arrears, and common unitholders of record on the applicable record date, as determined by 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 our 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.

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

 
·
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:

 
·
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 (other than preferred 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 (other than preferred unitholders), 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 based on a fully engineered reserve report) or June 30 (with respect to the third and fourth calendar quarters based on a fully engineered reserve report) 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.

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, 2011.

Unregistered Sales of Equity Securities

None.
 
Issuer Purchases of Equity Securities

None.


ITEM 6. SELECTED FINANCIAL DATA

The selected consolidated financial data presented as of and for the year ended December 31, 2011 and for the period from December 22, 2010 to December 31, 2010 is derived from our audited financial statements. The selected financial data for the period from January 1, 2010 to December 21, 2010 and as of and for the years ended December 31, 2009, 2008 and  2007 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 (1)
    
Predecessor
  
Thousands of Dollars
  
Year Ended
December 31,
2011
    
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
  
                                     
Statement of Operations Data:
                                    
Revenues:
                                    
Oil, natural gas and NGL
   $ 257,903     $ 6,661     $ 244,572     $ 69,823     $ 233,465     $ 163,368  
Processing fees and other
     1,965       24       8,814       2,978       47,605       7,949  
Total Revenues
     259,868       6,685       253,386       72,801       281,070       171,317  
Operating costs and expenses:
                                                
Lease operating
     66,488       1,784       76,512       33,328       90,424       77,767  
Production taxes
     17,613       483       17,657       7,587       14,566       12,954  
Transportation and processing
     3,956       88       11,673       3,926       26,189       4,728  
Inventory adjustment
     -       -       2,566       -       -       -  
Impairment of oil and gas properties
     -       -       -       28,338       451,440       -  
Depreciation, depletion and amortization
     78,354       2,130       66,482       16,993       49,309       42,889  
Accretion of asset retirement obligations
     2,702       77       3,674       3,585       3,004       2,751  
Management fees (3)
     -       -       10,486       12,018       12,018       11,482  
General and administrative and other
     31,666       763       32,041       19,279       14,703       20,652  
Bargain purchase gain
     -       -       -       (1,200 )     -       -  
Total operating costs and expenses
     200,779       5,325       221,091       123,854       661,653       173,223  
Income (loss) from operations
     59,089       1,360       32,295       (51,053 )     (380,583 )     (1,906 )
Other income (expenses):
                                                
Realized (losses) gains on commodity derivative contracts
     (72,053 )     (289 )     5,373       47,993       (34,666 )     6,861  
Unrealized gains (losses) on commodity derivative contracts
     120,478       (12,068 )     8,204       (111,113 )     169,321       (157,250 )
Gain on equity share issuance
     -       -       4,064       -       -       -  
Interest expense, net
     (45,527 )     (1,136 )     (22,179 )     (3,716 )     (12,417 )     (16,381 )
Other income (expense)
     -       -       4,264       2,657       (10,039 )     7  
Total other income (expense)
     2,898       (13,493 )     (274 )     (64,179 )     112,199       (166,763 )
Income (loss) before income taxes
     61,987       (12,133 )     32,021       (115,232 )     (268,384 )     (168,669 )
State tax benefit, net
     (850 )     66       (108 )     (182 )     (149 )     (25 )
Net income (loss)
     61,137       (12,067 )   $ 31,913     $ (115,414 )   $ (268,533 )   $ (168,694 )
Net (income) loss attributable to predecessor operations
     (49,091 )     4,968                                  
Less: Distribution on Class C convertible
preferred units
     (7,062 )     -                                  
Income (loss) available to other unitholders
     4,984       (7,099 )                                
General partner's interest in net income (loss)
     1,575       (7 )                                
Limited partners' interest in net income (loss)
   $ 3,409     $ (7,092 )                                
Net loss per limited partner unit (basic and diluted)
   $ 0.10     $ (0.21 )                                
Weighted average number of limited partner units outstanding (basic and diluted)
     35,874       33,444                                  
Other Financial Data:
                                                
Adjusted EBITDA (4)
   $ 181,755     $ 3,986     $ 116,152     $ 48,513     $ 78,465     $ 50,602  
Distributable cash flow (5)
     108,677       2,156                                  
Cash Flow Data:
                                                
Net cash provided by (used in):
                                                
Operating activities
   $ 60,074     $ 1,764     $ 95,945     $ 64,907     $ 75,282     $ 24,839  
Investing activities
     (54,153 )     (78,081 )     (956,877 )     (55,458 )     (137,161 )     (72,953 )
Financing activities
     9,317       78,512       903,448       (13,328 )     30,240       89,890  
Balance Sheet Data:
                                                
Working capital
   $ 26,418     $ (6,421 )       (2)   $ (74 )   $ 67,139     $ 27,356  
Total assets
     1,057,064       938,715         (2)     226,770       304,937       655,689  
Total debt
     500,000       452,000         (2)     86,450       88,750       226,275  
Non-controlling interests
     -       -         (2)     14,733       133,978       235,201  
Partners' capital
     414,841       377,151         (2)     (1,421 )     5,957       5,103  
 
 
(1)
These results of operations have been recast to include financial information for the Transferred Properties. Refer to Note 2 of the Notes to Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for the Partnership’s accounting presentation for transactions under common control.
 
(2)
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.”
 
(3)
Includes fees paid by the Fund to its general partner for the provision of certain administrative and acquisition services during the period from January 1 to December 21, 2010 and the years ended December 31, 2009, 2008 and 2007.
 
(4)
Adjusted EBITDA is a Non-GAAP financial measure. See reconciliation to its most comparable GAAP measure below.
 
(5)
Distributable Cash Flow is a Non-GAAP financial measure. See reconciliation to its most comparable GAAP measure below.


Non-GAAP Financial Measures

We include in this report the non-GAAP financial measures Adjusted EBITDA and Distributable Cash Flow and provide our calculations of Adjusted EBITDA and Distributable Cash Flow and reconciliations to their most directly comparable financial measures calculated and presented in accordance with GAAP.

Adjusted EBITDA

We define Adjusted EBITDA as net income:

 
·
Plus:
 
 
·
Interest expense, including realized and unrealized gains and losses on interest rate derivative contracts;
 
 
·
Depreciation, depletion, 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 — 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.

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

   
Partnership
    
Predecessor
  
Thousands of Dollars
  
Year Ended
December 31,
2011
    
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
  
Reconciliation of consolidated net income (loss) to Adjusted EBITDA:
                                    
Net income (loss)
   $ 61,137     $ (12,067 )   $ 31,913     $ (115,414 )   $ (268,533 )   $ (168,694 )
Unrealized (gains) losses on commodity derivative instruments
      (120,478 )      12,068        (8,204 )      111,113        (169,321 )      157,250  
Loss on modification of derivative instruments
     83,399       -       -       -       -       -  
Depletion, depreciation and amortization
     78,354       2,130       66,482       16,993       49,309       42,889  
Accretion of asset retirement obligations
     2,702       77       3,674       3,585       3,004       2,751  
Interest expense, net
     45,527       1,136       22,179       3,716       12,417       16,381  
State tax expense (benefit), net
     850       (66 )     108       182       149       25  
Impairment expense
     -       -       -       28,338       451,440       -  
General and administrative expense in excess of the administrative services fee
      30,264        708        -        -        -        -  
Adjusted EBITDA
   $ 181,755     $ 3,986     $ 116,152     $ 48,513     $ 78,465     $ 50,602  
                                                 
Reconciliation of Net Cash from Operating
                                                
Activities to Adjusted EBITDA:
                                                
Net cash provided by (used in) operating activities
   $ 60,074     $ 1,764     $ 95,945        64,907        75,282        24,839  
(Increase) decrease in working capital
     19,347       1,698       (1,651 )     (24,941 )     9,010       3,342  
Recognition of Predecessor equity awards
                     (3,470 )     -       -       -  
Timing differences related to excess general and administrative expense calculations
      (159 )      23        -        -        -        -  
Loss on modification of derivative instruments
     83,399       -       -       -       -       -  
Purchase of commodity derivative contracts
             -       -       -       2,694       7,546  
Amortization of costs of commodity derivative instruments
      -        -        -        (1,219 )      (7,981 )      -  
Interest expense (1)
     19,093       496       16,892       6,038       9,929       14,843  
State tax expense, current
     1       5       108       182       149       25  
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 )      -  
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
   $ 181,755     $ 3,986     $ 116,152     $ 48,513     $ 78,465     $ 50,602  

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

Distributable Cash Flow. We define distributable cash flow as Adjusted EBITDA less cash interest expense, maintenance capital expenditures, distributions to preferred unitholders, and the management incentive fee.  Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserve by our general partner) to the cash distributions we expect to pay our unitholders.  Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions.  Distributable cash flow is also an important financial measure for our unitholders as it serves as an indicator of our success in providing a cash return on investment.  Specifically, distributable cash flow indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates.  Distributable cash flow is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because yield-based securities and the yield is based on the amount of cash distributions the entity pays to a unitholder).

 
Distributable cash flow may not be comparable to similarly titled measures of another company because all companies may not calculate distributable cash flow in the same manner.  The table below summarizes our distributable cash flow for the period of December 22 through December 31, 2010 and the year ended December 31, 2011.

   
Year Ended
December 31,
2011
    
December 22, to
December 31,
2010
  
Net income (loss)
   $ 61,137     $ (12,067 )
Unrealized (gain)/loss on commodity derivatives contracts
      (120,478 )      12,068  
Loss on modification of derivative contracts
     83,399       -  
Depletion, depreciation and amortization
     78,354       2,130  
Accretion of asset retirement obligations
     2,702       77  
Interest expense, net
     45,527       1,136  
Income tax expense (benefit), net
     850       (66 )
General and administrative expense in excess of administrative services fee
      30,264        708  
Adjusted EBITDA
     181,755       3,986  
Maintenance capital expenditures
     (50,000 )     (1,359 )
Cash interest expense
     (18,082 )     (471 )
Distributions to preferred unitholders
     (3,424 )     -  
Management incentive fee earned
     (1,572 )     -  
Distributable cash flow
   $ 108,677     $ 2,156  
 

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 Form 10-K. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Information” in the front of this Form 10-K.

Overview

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

Our properties are located in 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, 2011, we had estimated net proved reserves of 34.2 MMBbl of oil and condensate, 198.6 Bcf of natural gas and 7.8MMBbl of NGLs, or 75.2 MMBoe and a standardized measure of $1.2 billion.

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 net 7.44% 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.

On October 3, 2011 we completed an acquisition of the Transferred Properties located in the Permian Basin, Ark-La-Tex and Mid-Continent areas from the Fund pursuant to the Purchase Agreement having an effective date of October 1, 2011. In 2010, the Predecessor acquired certain of these properties from Denbury Resources and Melrose Energy Company.  These assets acquired by our Predecessor are included in the Purchase Agreement.  The Partnership’s financial statements have been revised to include the results of operations of the Transferred Properties for all of 2011 and the period from December 22, 2010 to December 31, 2010 as the acquisition has been accounted for as a transaction between entities under common control.  The remainder of the Transferred Properties were acquired by the Predecessor prior to 2010. As of December 31, 2011 the Transferred Properties consisted of working interests in 1,669 gross (1,026 net) producing wells, of which we owned an approximate 61.46% average working interest.

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 $893.0 million. The acquisition-related costs for the Denbury Acquisition were approximately $1.2 million and are recorded as acquisition evaluation costs for 2010

On December 22, 2010, the Predecessor acquired certain oil and natural gas properties from Melrose Energy Company for $62.3 million.  The acquisition related costs for the Melrose Properties were approximately $0.2 million and were recorded as acquisition evaluation costs for 2010.


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 addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.
 
Oil Prices. The NYMEX-WTI 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).
 
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 1040 Btu and minimal sulfur and CO2 content and generally receives a premium valuation.
 
Price Volatility. Historically, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2011, the NYMEX-WTI oil price ranged from a high of $113.39 per Bbl to a low of $75.40 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $4.92 per MMBtu to a low of $2.84 per MMBtu. For the five years ended December 31, 2011, the NYMEX-WTI oil price ranged from a high of $145.31 per Bbl to a low of $30.28 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $13.31 per MMBtu to a low of $1.83 per MMBtu.  Natural gas prices have experienced a continuous decrease in late 2011 and early 2012.  Future decreases in the natural gas market price could have a negative impact on revenues, profitability, and cash flow.


Commodity Derivative Contracts
 
Our hedging policy is intended to reduce the impact to our cash flows from commodity price volatility. We intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our 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 the Fund 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.
 
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 the Fund and its Affiliates – Services Agreement.”


Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled 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 Financial Measures.”

Distributable Cash Flow

Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserve by our general partner) to the cash distributions we expect to pay our unitholders.  For our definition of Distributable Cash Flow see “Item 6. Selected Financial Data – Non-GAAP Financial Measures.”

Distributable cash flow should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our distributable cash flow may not be comparable to similarly titled measures of another company because all companies may not calculate distributable cash flow in the same manner.  For further discussion, see “Item 6. Selected Financial Data – Non-GAAP Financials Measures.”

Outlook

In 2012, our capital spending program is expected to be approximately $61.9 million, excluding acquisitions. We anticipate spending approximately 70.1% in the Permian Basin primarily on infill drilling and waterflood expansion and 25.2% in the Ark-La-Tex area primarily on recompletions and artificial lift implementation.


As of December 31, 2011, we had the following derivative instruments outstanding:

Commodity
  
 Index
  
2012
    
2013
    
2014
    
2015
    
2016
  
Oil positions:
                                  
Swaps
                                  
Hedged Volume (Bbls/d)
  
WTI
     4,025       4,143       3,711       2,940       270  
Average price ($/Bbls)
       $ 98.72     $ 98.23     $ 97.70     $ 97.27     $ 97.63  
Collars
                                            
Hedged Volume (Bbls/d)
  
WTI
                     425       1,025          
Average floor price ($/Bbls)
                       $ 90.00     $ 90.00          
Average ceiling price ($/Bbls)
                       $ 106.50     $ 110.00          
                                             
Natural gas positions:
                                            
Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     30,392       29,674       25,907       6,100          
Average price ($/MMBtu)
       $ 5.86     $ 6.07     $ 6.23     $ 5.52          
Basis Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     20,723       18,466       17,066       14,400          
Average price ($/MMBtu)
       $ (0.15 )   $ (0.17 )   $ (0.19 )   $ (0.19 )        
Collars
                                            
Hedged Volume (MMBtu/d)
  
Henry Hub
     2,623       2,466       4,966       18,000          
Average floor price ($/MMBtu)
       $ 6.50     $ 6.50     $ 5.74     $ 5.00          
Average ceiling price ($/MMBtu)
       $ 8.60     $ 8.65     $ 7.51     $ 7.48          
 
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 2012. 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:

 
·
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 of the Notes to Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” 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 depreciation, depletion, and amortization (“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.

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, 2011 reserve report had been $10.00 less per Bbl, then the standardized measure of our estimated proved reserves as of December 31, 2011 would have decreased by approximately $164.8 million, from $1.2 billion to $1.0 billion. If the SEC prices used for our December 31, 2011 reserve report had been $1.00 less per MMBtu, then the standardized measure of our estimated proved reserves as of December 31, 2011 would have decreased by approximately $95.9 million, from $1.2 billion to $1.1 billion.


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 DD&A expense and revisions in such estimates may alter the rate of future depletion expense. Holding all other factors constant, if reserves are revised upward, earnings would increase due to lower depletion expense. Likewise, if reserves are revised downward, earnings would decrease due to higher depletion expense or due to a ceiling test write-down. For example, a 10% negative revision to proved reserves as of December 31, 2011 would increase the DD&A rate by approximately 0.2%. This represents an increase of DD&A expense of $1.78 per Boe, or a change from $16.32 to $18.10 per Boe for the year ended December 31, 2011. This estimated impact is based on current data as of December 31, 2011 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. 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, 2011 by $6.1 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 oil and natural gas reserves.

Predecessor’s Unevaluated Properties

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 unevaluated properties held by the Predecessor were evaluated and assigned to properties in September 2011.  A portion of these properties were subsequently transferred to the Partnership in conjunction with the Purchase Agreement in October 2011 and were included in the Partnership’s historical statement of financial position as the transfer was between entities under common control.  See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information on the Partnership’s accounting presentation

Results of Operations

Because affiliates of the Fund own 100% of our general partner and an aggregate 67% limited partner interest in us including 11,297,737 of our common units and all of our preferred and subordinated units, each acquisition of assets from the Predecessor is considered a transfer of net assets between entities under common control. As a result, we are required to revise our financial statements to include the activities of such assets for all periods presented by the Partnership, similar to a pooling of interests, to include the financial position, results of operations, and cash flows of the assets acquired and liabilities assumed.  The table set forth below includes the recast historical financial information as if the acquired assets were owned by us for all periods presented for the Partnership.
 
 The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets have been prepared from the Predecessor’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.

Factors Affecting the Comparability of our Historical Financial Results

Prior Year. Our current year results are not comparable to the Partnership’s year end 2010 results as our prior year results only include activity from December 22, 2010, the date of our IPO.

Comparability to the Predecessor. The comparability of our results for the year ended December 31, 2011 and the Predecessor’s results for the period January 1, to December 21, 2010 is impacted as follows:

·
Our results for the year ended December 31, 2011 include additional operating results from certain properties that were contributed to us in connection with the Predecessor’s Denbury Acquisition, which occurred in May 2010; and therefore not part of our Predecessor’s operating results for the entire period.
·
Our results for the year ended December 31, 2011 include additional operating results for the Melrose Properties as if we owned the properties for the entire year to account for these assets which were part of a transaction between entities under common control. The results from these assets were not part of the Predecessors results from the period of January 1 to December 21, 2010 as the Predecessor acquired them on December 22, 2010.
 
 
·
Our results for the year ended December 31, 2011 do not include the operating results of certain properties owned by the Predecessor for the period from January 1 to December 21, 2010 that were not contributed to us as part of the IPO Assets and the Transferred Properties.

Accordingly, we have not presented a comparison of our results for the year ended December 31, 2011 against any of these 2010 periods.


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 (1)
    
Predecessor
  
   
Year
Ended
December 31,
2011
    
December 22
to
December 31,
2010
    
January 1
to
December 21,
2010
    
Year
Ended
December 31,
2009
  
Revenues
                        
Oil sales
   $ 162,654     $ 3,990     $ 165,565     $ 41,188  
Natural gas sales
     81,232       2,412       66,014       21,592  
NGLs sales
     14,017       259       12,993       7,043  
Processing and other
     1,965       24       8,814       2,978  
Total Revenue
     259,868       6,685       253,386       72,801  
Operating Expenses
                                
Lease operating expenses
     66,488       1,784       76,512       33,328  
Production and other taxes
     17,613       483       17,657       7,587  
Processing and transportation
     3,956       88       11,673       3,926  
Inventory adjustment
     -       -       2,566       -  
Total production expenses
     88,057       2,355       108,408       44,841  
Impairment of oil and gas properties
     -       -       -       28,338  
Depreciation, depletion and amortization
     78,354       2,130       66,482       16,993  
Accretion of asset retirement obligations
     2,702       77       3,674       3,585  
Management fees
     -       -       10,486       12,018  
Offering costs
     -       -       5,148       -  
Bargain purchase gain
     -       -       -       (1,200 )
General and administrative and other
     31,666       763       26,893       19,279  
Total operating expenses
     200,779       5,325       221,091       123,854  
Operating income (loss)
     59,089       1,360       32,295       (51,053 )
Other income (expense):
                                
Equity in earnings of Ute Energy, LLC
     -       -       3,782       2,675  
Dividends on investment in marketable equity securities
     -       -       -       233  
Gain (loss) on investment in marketable equity securities
     -       -       -       394  
Realized (loss) gain on commodity derivative contracts
     (72,053 )     (289 )     5,373       47,993  
Unrealized gains (losses) on commodity derivative contracts
     120,478       (12,068 )     8,204       (111,113 )
Gain on equity share issuance
     -       -       4,064       -  
Interest expense
     (45,527 )     (1,136 )     (22,179 )     (3,716 )
Other income (expense):
     -       -       482       (645 )
Total other income (expense), net
     2,898       (13,493 )     (274 )     (64,179 )
Income (loss) before income taxes
     61,987       (12,133 )     32,021       (115,232 )
State tax benefit
     (850 )     66       (108 )     (182 )
Net income (loss)
     61,137     $ (12,067 )   $ 31,913     $ (115,414 )
Production data(2):
                                
Oil (MBbls)
     1,766       49       2,172       739  
Natural gas (MMcf)
     17,386       524       14,754       5,359  
Natural gas liquids (MBbls)
     427       9       282       207  
Total (Mboe)
     5,091       145       4,913       1,839  
Average Net Production (Boe/d)
     13,947       14,533       13,839       5,038  
Average sales price per unit (3):
                                
Oil (per Bbl)
   $ 92.10     $ 81.43     $ 76.23     $ 55.74  
Natural gas (per Mcf)
   $ 4.80     $ 4.73     $ 4.47     $ 4.03  
Natural gas liquids (per Bbl)
   $ 53.30     $ 64.75     $ 46.07     $ 34.02  
Average unit cost per Boe:
                                
Lease operating expense
   $ 13.06     $ 12.28     $ 15.57     $ 18.12  
Production and other taxes
   $ 3.46     $ 3.32     $ 3.59     $ 4.13  
Management fees
   $ -     $ -     $ 2.13     $ 6.54  
Depreciation, depletion and amortization
   $ 15.39     $ 14.66     $ 13.53     $ 9.24  
General and administrative expenses
   $ 6.22     $ 5.24     $ 5.47     $ 10.48  
 
 
(1)
These results of operations have been recast to include financial information for assets acquired under common control. Refer to Note 2 of Notes to Financial Statements included in Item 8. “Financial Statements and Supplementary Data for the Partnership’s accounting presentation for transactions under common control.
 
(2)
Includes certain volumes for natural gas (461 MMcf for 2011 and 14MMcf for 2010) and natural gas liquids (164 MBbls for 2011 and 5 MBbls for 2010) for which revenues are reported on a net basis.
 
(3)
Does not include impact of derivative instruments.
 

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 the contribution in our consolidated financial statements at the Fund’s carryover 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, $200.0 million of debt assumed from the Fund and asset retirement obligations of $18.3 million. Our operating results for the year ended December 31, 2011 and the ten day period from December 22, 2010 to December 31, 2010 are presented below.

Year Ended December 31, 2011

We recorded net income of $61.1 million during the year ended December 31, 2011.The net income was primarily driven by our operating income of $59.1 million and a net gain on commodity derivative contracts of $48.4 million partially offset by interest expense of $45.5 million.

Sales Revenues. Sales revenues of $259.9 million for the year ended December 31, 2011 consisted of oil and condensate sales of $162.7 million, natural gas sales of $81.2 million and NGL sales of $14.0 million. Oil sales volumes were 1,766 MBbl and the average sales price was $92.10 per Bbl. Natural gas sales volumes were 17,386 MMcf and the average sales price was $4.80 per Mcf. NGL sales volumes were 427 MBbls and the average sales price was $53.30 per Bbl. Total average sales price was $53.18 per Boe. Production for the year ended December 31, 2011 was 13.9 MBoe/d. 51% of sales were from the Permian area, 34% were from Ark-La-Tex, 11% from Mid-Continent and 4% were from Gulf Coast.

Effects of Commodity Derivative Contracts.  Primarily due to increases in oil and natural gas prices, we recorded a net gain from our commodity derivatives program during the period of $48.4 million, composed of a realized loss of $72.1 million and an unrealized gain of $120.5 million.

Production Expenses. Our production expenses were $88.1 million for the period, consisting of $66.5 million in lease operating expenses or $13.06 per Boe and $17.6 million in production and other taxes or $3.46 per Boe.  60% of our production expenses were from the Permian area.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion, and amortization expenses were $78.4 million, or $15.39 per Boe produced during the period.
 
General and Administrative and Other Expenses. Our general and administrative and other expenses were $31.7 million, or $6.22 per Boe. This consisted primarily of general and administrative costs allocated from the Fund of which only $2.5 million was be paid in cash as administrative services fees pursuant to the services agreement.  See “Summary of Significant Accounting Policies” included under Note 2 of the Notes to Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for a discussion of our general and administrative expenses.

Interest Expense, net. Interest expense, related to the $500.0 million of borrowings under credit facility was $45.5 million during the period.

Period from December 22, 2010 through December 31, 2010

We recorded a net loss of $12.1 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 $12.4 million and interest expense of $1.1 million  partially offset by our operating income of $1.4 million.

Sales Revenues. Sales revenues of $6.7 million for the period consisted of oil and condensate sales of $4.0 million, natural gas sales of $2.4 million and NGL sales of $0.3 million. Oil sales volumes were 49 MBbls and the average sales price was $81.43 per Bbl. Natural gas sales volumes were 524 MMcf and the average sales price was $4.73 per Mcf. NGL sales volumes were 9 MBbls and the average sales price was $64.75 per Bbl. Total average sales price was $48.27 per Boe. Production for the 10-day period was 14.5 Boe/d.


Effects of Commodity Derivative Contracts. Due to increases in oil and natural gas prices, we recorded a net loss from our commodity derivatives program during the period of $12.2 million, composed of a realized loss of $0.3 million and an unrealized loss of $12.4 million.

Production Expenses. Our production expenses were $2.4 million for the period, consisting of $1.8 million in lease operating expenses or $12.28 per Boe and $0.5 million in production and other taxes or $3.32 per Boe.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expenses were $2.1 million, or $14.66 per Boe produced during the period.
 
General and Administrative and Other Expenses. Our general and administrative and other expenses were $0.8 million, or $5.24 per Boe. This consisted primarily of non-cash allocated general and administrative costs from the Fund of which only $0.1 million was paid in cash in the form of an administrative services fee.  See “Summary of Significant Accounting Policies” included under Note 2 of the Notes to Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for a discussion of our general and administrative expenses.

Interest Expense, net. Interest expense, related to the $452.0 million of borrowings under our credit facility incurred in connection with our IPO, was $1.1 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 between the periods presented is impacted by:

 
·
The following significant acquisitions by our Predecessor:
 
§
The Denbury Acquisition in May 2010 for $893.0 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 completion 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”.

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 2010 period 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 Assets, were the primary reasons for the increases.

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 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.

Liquidity and Capital Resources

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

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under our credit facility, 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 derivatives 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, 2011 our liquidity of $147.0 million consisted of $17.4 million of cash on hand, and $129.6 million of availability 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, 2011, our $750.0 million credit facility had borrowing capacity of $129.6  million ($630.0 million borrowing base less $500.0 million of outstanding borrowings and $0.4 million of outstanding letters of credit.) 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. On July 13, 2011, we received an interim borrowing base redetermination under our Credit Agreement which increased the borrowing base to $330.0 million. We requested and received this interim redetermination as a result of improvements in our net derivative position due to the buyup of our existing oil fixed price swap contracts in June 2011. On October 3, 2011 in connection with the acquisition of the Transferred Properties, we amended our revolving credit facility to, among other things, increase the borrowing base by $300.0 million, resulting in a total borrowing base of $630.0 million. The administrative agent of our Credit Agreement has accepted this amendment in lieu of our semiannual redetermination required on November 1, 2011. In addition, we may request additional capacity for any acquisition with a purchase price in excess of the lesser of $50.0 million or 10% of the existing borrowing base at the time.


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, 2011, we had $0.4 million in letters of credit outstanding for utilities.

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 credit facility borrowings and debt and equity issuances, to fund our acquisition and expansion capital expenditures. See Note 7 and Note 9 of the Notes to Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data”.

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, 2011, we had a positive working capital balance of $26.4 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 2012, we have estimated our maintenance capital expenditures to be approximately $50.0 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, 2012, including potential acquisitions of producing properties from the Fund, we have not estimated any growth capital expenditures related to acquisitions, as we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts.

The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2012. 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

We are party to a five-year credit agreement that governs our $750.0 million revolving credit facility with a current borrowing base of $630.0 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 2012.

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 $0.2 million based on our outstanding borrowings as of December 31, 2011.

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 our assets; make certain investments, acquisitions or certain restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; 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, 2011, 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 90 days and reviewed quarterly financial statements within 45 days after quarter end.

As of December 31, 2011, we had $500.0 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. Currently, we have in place oil and natural gas swaps covering significant portions of our estimated oil production through December 31, 2016 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, 2011 for the periods indicated through December 31, 2016.

Commodity
  
 Index
  
2012
    
2013
    
2014
    
2015
    
2016
  
Oil positions:
                                  
Swaps
                                  
Hedged Volume (Bbls/d)
  
WTI
     4,025       4,143       3,711       2,940       270  
Average price ($/Bbls)
       $ 98.72     $ 98.23     $ 97.70     $ 97.27     $ 97.63  
Collars
                                            
Hedged Volume (Bbls/d)
  
WTI
                     425       1,025          
Average floor price ($/Bbls)
                       $ 90.00     $ 90.00          
Average ceiling price ($/Bbls)
                       $ 106.50     $ 110.00          
                                             
Natural gas positions:
                                            
Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     30,392       29,674       25,907       6,100          
Average price ($/MMBtu)
       $ 5.86     $ 6.07     $ 6.23     $ 5.52          
Basis Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     20,723       18,466       17,066       14,400          
Average price ($/MMBtu)
       $ (0.15 )   $ (0.17 )   $ (0.19 )   $ (0.19 )        
Collars
                                            
Hedged Volume (MMBtu/d)
  
Henry Hub
     2,623       2,466       4,966       18,000          
Average floor price ($/MMBtu)
       $ 6.50     $ 6.50     $ 5.74     $ 5.00          
Average ceiling price ($/MMBtu)
       $ 8.60     $ 8.65     $ 7.51     $ 7.48          

For more information on the oil and natural gas swaps and swap prices and resulting adjusted swap prices in place as of December 31, 2011, See “Item 7A.  Quantitative and Qualitative Disclosure About Market Risk.”


Counterparty Exposure

As of December 31, 2011, our open commodity derivative contracts were in a net payable position. All of our commodity derivative contracts are with major financial institutions. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss. Although we have the ability to elect to enter into netting agreements with certain of our counterparties, we have properly presented all asset and liability positions without netting.  As of December 31, 2011, all of our counterparties have performed pursuant to their commodity derivative contracts. In the fourth quarter of 2011, we incurred $0.5 million in transaction costs to novate certain commodity derivative contracts from the legacy European counterparty to a North American counterparty.

The following table presents our asset and liability positions with our counterparties both before and after credit risk adjustments as of December 31, 2011:
 
   
Credit Risk
  
   
Gross
    
Adjustment
    
Adjusted
  
Assets
   $ 106,059     $ (2,826 )   $ 103,233  
Liabilities
     (2,588 )     86       (2,502 )
Net
     103,471       (2,740 )     100,731  

Cash Flows

Cash flows provided (used) by type of activity were as follows for the periods indicated:
 
   
Partnership
    
Predecessor
  
   
Year Ended
December 31,
2011
    
December 22
through
December 31,
2010
    
January 1
through
December 21,
2010
    
Year Ended
December 31,
2009
  
Net cash provided by (used in):
                        
Operating activities
   $ 60,074     $ 1,764     $ 95,945     $ 64,907  
Investing activities
     (54,153 )     (78,081 )     (956,877 )     (55,458 )
Financing activities
     9,317       78,512       903,448       (13,328 )
 
Operating Activities

Partnership

Our cash flows from operating activities provided $60.1 million for the year ended December 31, 2011 and $1.8 million for the period from December 22, 2010 to December 31, 2010. The increase in cash provided by operating activities was primarily due to an increase in net income caused by increased production levels from acquisitions of oil and natural gas properties in 2011 as well as improved prices period over period.

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.


Investing Activities

Partnership

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

Our cash used in investing activity was $54.2 million for the year ended December 31, 2011. The increase in net cash outflow period over period was primarily due to an increase in capital workover projects to develop existing producing assets as well as capital projects on assets acquired in 2011.

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.

Financing Activities

Partnership

Our cash flows from financing activities comprised $9.3 million in cash provided for the year ended December 31, 2011 and $79.0 million  for the period from December 22, 2010 to December 31, 2010. The net increase in cash provided by financing activities in 2011 was primarily due to contributions made by the Predecessor.

Predecessor

The Predecessor’s cash flows from financing activities comprised $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.

Capital Requirements

We currently expect 2012 spending for the development of our oil and natural gas properties to be approximately $61.9 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 March 15, 2012, distributions to all of our unitholders at the minimum quarterly distribution rate for 2012 would total approximately $59.5 million.
 
On October 4, 2011, we announced the board of directors of our general partner approved an increase in the quarterly cash distribution to all common and subordinated units to $0.4750 per unit, representing a $0.25 annualized increase to $1.90 per common and subordinated unit. This increase took effect with the cash distribution for the fourth quarter of 2011 paid in February 2012. This increase approximated an additional annual payable to unitholders of $68.5million.
 
 
On October 3, 2011, we issued 16,666,667 Preferred Units to the Fund as payment for the oil and gas properties acquired in the Purchase Agreement. These units receive annualized distributions of $0.84 per Preferred Unit beginning with the cash distribution for the fourth quarter of 2011 paid in February 2012. The annual payable to preferred unitholders will approximate $14.0 million.
 
Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations above maintenance capital expenditures. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to finance any significant acquisition of oil and natural gas properties in 2012.

Contractual Obligations

In the table below, we set forth our contractual cash obligations as of December 31, 2011. The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective. 

   
Payments Due by Period
  
   
Total
    
Less than
1 Year
    
1 - 3 Years
    
4 - 5 Years
    
After 5
Years
  
Total debt (1)
   $ 500,000     $ -     $ -     $ 500,000     $ -  
Estimated interest payments (2)
     93,892       23,543       46,987       23,362       -  
Asset retirement obligations (3)
     65,701       348       476       1,319       63,558  
Total
   $ 659,593     $ 23,891     $ 47,463     $ 524,681     $ 63,558  
 
 
(1)
Total balance of our senior secured credit facility will mature in December 2015.
 
(2)
Amounts represent the expected cash payments for interest based on the debt outstanding, unused portion of our credit facility and letters of credit as of December 31, 2011. Rates used to calculate these estimated payments include 2.78% on the unhedged portion of debt outstanding, 4.63% weighted average interest rate on the hedged portion of debt outstanding, a 0.5% commitment fee on the $129.6 million  unused portion of the facility, 2.5% on the letter of credit outstanding.
 
(3)
Present value of obligations at December 31, 2011.

Off–Balance Sheet Arrangements

As of December 31, 2011, 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 of the Notes to Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data”.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.

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


Commodity Price Risk

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

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

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

We use swaps as a mechanism for managing commodity price 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, 2011 for the periods indicated through December 31, 2016.

Commodity
  
 Index
  
2012
    
2013
    
2014
    
2015
    
2016
  
Oil positions:
                                  
Swaps
                                  
Hedged Volume (Bbls/d)
  
WTI
     4,025       4,143       3,711       2,940       270  
Average price ($/Bbls)
       $ 98.72     $ 98.23     $ 97.70     $ 97.27     $ 97.63  
Collars
                                            
Hedged Volume (Bbls/d)
  
WTI
                     425       1,025          
Average floor price ($/Bbls)
                       $ 90.00     $ 90.00          
Average ceiling price ($/Bbls)
                       $ 106.50     $ 110.00          
                                             
Natural gas positions:
                                            
Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     30,392       29,674       25,907       6,100          
Average price ($/MMBtu)
       $ 5.86     $ 6.07     $ 6.23     $ 5.52          
Basis Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     20,723       18,466       17,066       14,400          
Average price ($/MMBtu)
       $ (0.15 )   $ (0.17 )   $ (0.19 )   $ (0.19 )        
Collars
                                            
Hedged Volume (MMBtu/d)
  
Henry Hub
     2,623       2,466       4,966       18,000          
Average floor price ($/MMBtu)
       $ 6.50     $ 6.50     $ 5.74     $ 5.00          
Average ceiling price ($/MMBtu)
       $ 8.60     $ 8.65     $ 7.51     $ 7.48          
 

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 asset as of December 31, 2011 by $6.1 million. The sensitivity was calculated without regards to any applicable credit risk adjustments.

Interest Rate Risk

As of December 31, 2011, we had debt outstanding of $500.0 million, with a weighted average interest rate of LIBOR plus 2.5%, or 2.78%. . 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. For additional information please refer to Note 5 of the Notes to Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data”.

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, 2011, our open commodity derivative contracts were in a net asset position with a fair value of $76.8 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 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 credit facility that also carry investment grade ratings. Several of our significant customers for oil and natural gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

 
ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our Chief Executive Officer (“CEO”), our principal executive officer and Chief Financial Officer (“CFO”), our principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, the "Exchange Act") as of December 31, 2011. 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. As a result of the material weaknesses in internal control over the inputs with respect to the depreciation, depletion, and amortization calculation (“DD&A”) and the review of calculations related to several accounts as described below, the principal executive officer and the principal financial officer concluded that the Company’s disclosure controls and procedures were ineffective as of December 31, 2011.
 
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a -15(f) and 15d -15(f) under the Exchange Act). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. It consists of policies and procedures that:
 
 
· 
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

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

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

Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2011, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in “Internal Control — Integrated Framework.” As a result of the material weaknesses in internal control over the inputs with respect to the DD&A calculation and the review of calculations related to several accounts as described below, management has concluded that, as of December 31, 2011, the Company’s internal control over financial reporting was not effective.  A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis.
 
 
Management determined the following material weaknesses existed as of December 31, 2011:
 
 
· 
We did not maintain effective controls over the completeness and accuracy of the inputs with respect to the DD&A calculation. Specifically, we did not develop detailed procedures for the accounting staff to follow in order to provide reasonable assurance that the inputs to the calculation are complete and accurate.

 
· 
We did not maintain effective controls over the completeness and accuracy of certain calculations used in recording mark to market for derivative expense, the general and administrative allocation and ad valorem taxes. Specifically, we did not maintain effective controls related to the detail review of these calculations.
 
These control deficiencies resulted in immaterial misstatements and audit adjustments to the following accounts: mark-to-market expenses for derivatives and long term derivative assets and liabilities, general and administrative expenses and contributions from the Predecessor, DD&A expenses and accumulated DD&A, ad valorem tax payables and ad valorem tax expenses. Additionally, these control deficiencies could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, the Partnership's management has determined these control deficiencies constitute material weaknesses.
 
The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
 
REMEDIATION OF MATERIAL WEAKNESSES
 
As previously reported in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, we determined that our internal control over financial reporting and disclosure controls and procedures were ineffective as the result of several material weaknesses.
 
In response to the material weaknesses, our management, including the principal executive officer and principal financial officer, chief accounting officer and controller, has been committed to remediating the previously disclosed material weaknesses in internal control over financial reporting by enhancing existing controls and introducing new controls in all necessary areas by implementing a remediation plan in 2011 (the “Plan”) to address the previously disclosed material weaknesses. The Plan was administered by key leaders from cross functional groups of the organization. The Plan ensured that each area affected by a material weakness was put through a comprehensive remediation process. The remediation process entailed a thorough analysis which included the following phases:
 
 
· 
Define and assess the control deficiency: ensure a thorough understanding of the “as is” state, process owners, and gaps in the control deficiency;

 
· 
Design and evaluate a remediation action for each weakness for each affected area: validate or improve the related policy and procedures, evaluate skills of the process owners with regards to the policy and adjust as required;

 
· 
Implement specific remediation actions: train process owners; allow time for process adoption and adequate transaction volume for next steps;
 
 
· 
Test and measure the design and effectiveness of the remediation plan, and test and provide feedback on the design and operating effectiveness of the updated controls; and
 
 
· 
Management review and acceptance of completion of the remediation effort.

The status of remediation was reviewed with the Audit Committee who was advised of issues encountered and key decisions reached by management.
 

Remediated Material Weaknesses

During 2011, management took the following actions to remediate the material weaknesses:
 
Adequate Staffing Levels, Communication and Month End Close Process
 
Description of Material Weakness as of December 31, 2010
 
The Company lacked adequate staffing levels and communication throughout the organization resulting 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.  
 
Description of 2011 Remediation Actions
 
 
· 
To address the lack of adequate accounting and finance resources within the accounting group, and to improve the overall quality and level of experience in our finance and accounting organization, we replaced our Chief Accounting Officer in August, 2011. During 2011, we also added a Controller, an Assistant Controller, a Director of Corporate Accounting and Financial Reporting, a Director of Operations Accounting, a Tax Manager and a Compliance and Integration Manager as well as other personnel into our finance and accounting organization. Since December 31, 2010, we have added sixteen net personnel to our accounting and finance department. Together these personnel are providing an additional level of review and governance with respect to the preparation and review of our quarterly and annual consolidated financial statements.
 
 
· 
We implemented new controls and redesigned existing procedures and controls related to our monthly and quarterly close processes including account reconciliations, monthly close and reporting procedures to ensure all close tasks are completed, variance analysis of financial statement fluctuations, appropriate level of supporting documentation prior to journal entries being posted into the general ledger and increased levels of review and approval.
 
 
· 
Starting in 2011, we require quarterly certification by members of management to raise issues that may impact the quarterly financial reporting process.
 
 
· 
We recognize that communication between groups is important to improving financial reporting accuracy and therefore have established frequent communication meetings between the Accounting and Operations groups.
 
 
· 
All significant technical and complex accounting and financial reporting issues are subject to a review process in which the issue is thoroughly researched, discussed and concluded upon by accounting and financial reporting management.
 
 
· 
We reviewed our accounting policies and procedures with the assistance of an outside consulting firm and as a result additional policies and procedures have been implemented and others strengthened.
 
 
· 
We conclude that these remediation efforts have augmented our staffing levels, improved our communications and strengthened our overall month end close and financial reporting processes; the material weakness at the control environment level was effectively remediated as of December 31, 2011.
 
IT Systems
 
Description of Material Weakness as of December 31, 2010
 
The Company’s information technology environment lacked segregation of duties, controls over the change management processes for the related financial reporting systems, and integration of key systems.
 
 
Description of 2011 Remediation Actions
 
 
· 
Segregation of Duties - During the fourth quarter of 2011, we performed a broad and detailed analysis of user access to the applications we have determined to have a material impact on our financial reporting. As part of this review, security groups were defined and users were assigned to a specific security group.  Once the groups were defined within the system a segregation of duties matrix was used to identify any conflicts built into the groups.  These conflicts were either removed or compensating controls identified.  On a go forward basis, new user access or changes to an employee’s access will be in accordance with the defined security group structure.

 
· 
In addition, detailed quarterly security reviews have been instituted during the fourth quarter of 2011. We monitor the segregation of duties and system access rights of those employees with access to the financial systems to identify any grants of incompatible user access rights or any user access rights resulting from subsequent changes or modifications to groups. We conclude these remediation efforts have improved our controls over segregation of duties and the material weakness was effectively remediated at December 31, 2011.

 
· 
Change Management - During the fourth quarter of 2011, we implemented policies and procedures to control changes to the production environment.  Procedures address the authorization of changes, user acceptance testing, the retention of adequate supporting documentation, as well as segregation of duties within the change control process.  The Company also purchased and implemented a ticketing software package to assist in the monitoring of change management.  Additionally, access to production files has been limited to appropriate personnel in the IT group. We conclude these remediation efforts have improved our change management controls and the material weakness was effectively remediated at December 31, 2011.

 
· 
Integration of Key Systems – The original material weakness in 2010 relates to our properties and their associated attributes, including working interest and net revenue interest, not being consistent across our accounting and production systems. The Company implemented processes to fully reconcile data across the systems, including defining specific procedures for adding new wells or making changes to existing well data. A reconciliation project was undertaken in 2011 to review and validate property ownership attributes within the accounting and production systems. The Company implemented an acquisition and drop down process that includes comprehensive validation procedures around ownership interests, verifying that all properties are accurately reflected in the correct legal entity and all associated data is properly integrated across the systems.  We conclude these remediation efforts have improved our system integration and the material weakness was effectively remediated at December 31, 2011.
 
Full Cost Ceiling Impairment Test Calculation
 
Description of Material Weakness as of December 31, 2010
 
The Company 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 calculation.
 
Description of 2011 Remediation Actions
 
 
·
We have updated our policies and procedures for the calculation of the Ceiling Impairment Test.   Furthermore, we have developed detailed procedures which are followed by accounting staff to provide reasonable assurance that all inputs are included in the calculation, are tied to supporting documentation, and the calculation and any resulting journal entries are reviewed by a supervisor and has the appropriate level of supporting documentation prior to being posted into the general ledger.  Furthermore, the calculation is reviewed by higher level accounting personnel. We have assessed the design and tested the operating effectiveness of the key controls over the full cost ceiling impairment test calculation and conclude that the material weakness was effectively remediated at December 31, 2011.

 
Nonperformance Risk Adjustment
 
Description of Material Weakness as of December 31, 2010
 
The Company 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.
 
Description of 2011 Remediation Actions
 
 
·
We have implemented additional controls to incorporate an assessment of nonperformance risk when measuring the fair value of our derivative contracts with respect to ASC 820-10.  Procedures are followed by accounting staff to provide reasonable assurance that all inputs are included in the calculation, are tied to supporting documentation, and the calculation is mathematically accurate.  The calculation and resulting journal entries are reviewed by a supervisor who also verifies that there is an appropriate level of supporting documentation prior to the journal entry being posted into the general ledger.  Furthermore, the calculation and journal entries are reviewed by higher level accounting personnel.  We have assessed the design and tested the operating effectiveness of the key controls over the nonperformance risk adjustment process and conclude that the material weakness was effectively remediated at December 31, 2011.
 
Gas Imbalances
 
Description of Material Weakness as of December 31, 2010
 
The Company did not design and operate effective controls to ensure that gas imbalance liabilities were appropriately recorded, resulting in audit adjustments in 2010.
 
Description of 2011 Remediation Actions
 
 
·
We have implemented a gas balancing policy that provides the methodology and accounting procedures to determine, monitor, and record the Company’s gas imbalances.  We implemented additional levels of review including agreeing the inputs to supporting documentation and the recalculation of the gas imbalance computation.  Furthermore, there is additional higher management review and approval of the computation of the gas imbalance liabilities and resulting journal entry. We have assessed the design and tested the operating effectiveness of the key controls over the gas imbalance process and conclude that the material weakness was effectively remediated at December 31, 2011.
 
Suspended Revenue and Revenue Clearing Balances and Outside Owners’ Interests Accruals
 
Description of Material Weakness as of December 31, 2010
 
The Company 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.
 
Description of 2011 Remediation Actions
 
 
·
Suspended Revenue and Revenue Clearing Balances - During the fourth quarter of 2011, we improved the format for the suspended revenue and revenue clearing account reconciliations to provide additional detail for analysis around the account balances. In addition, we defined roles and responsibilities for the preparation and review of the reconciliations and provided training to accounting staff to provide reasonable assurance that the accounts were appropriately reconciled. We have assessed the design and tested the operating effectiveness of the key controls over the Suspended Revenue and Revenue Clearing Balances and conclude that the material weakness was effectively remediated at December 31, 2011.

 
·
Outside Owners’ Interests Accruals - We completed a project to review our property interests and updated the associated systems.  We also implemented controls to provide reasonable assurance that changes to working interests within the systems are reviewed by management on a monthly basis.  We have assessed the design and tested the operating effectiveness of the key controls over the Outside Owners’ Interest Accruals and conclude that the material weakness was effectively remediated at December 31, 2011.
 
 
Acquisitions and Conveyance Accounting
 
Description of Material Weaknesses as of December 31, 2010
 
The Company 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.
 
The Company 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.
 
Description of 2011 Remediation Actions
 
 
·
During the fourth quarter of 2011, we developed detailed acquisition procedures which are followed by accounting staff to provide reasonable assurance that assets are integrated into our systems, conveyance accounting issues are addressed, and the transaction and any technical accounting issues are reviewed by higher level accounting personnel. Furthermore, detailed analysis and review is performed at multiple levels during the process to identify any significant issues. We conclude that these remediation efforts have improved the controls over our acquisition process and conveyance accounting and the material weaknesses were effectively remediated at December 31, 2011.
 
Executive and Management Compensation Arrangements
 
Description of Material Weaknesses as of December 31, 2010
 
The Company 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.
 
Description of 2011 Remediation Actions
 
 
·
We implemented controls to capture all executive and management compensation arrangements, including a review of the agreements, updates to any plans and plan activity, and updates to performance assumptions.  Furthermore, we implemented a process to track and record restricted unit movements within the employee Long-Term Incentive Plan.

 
·
We record a monthly journal entry for compensation expense. The calculation and any resulting journal entries are reviewed by higher level accounting personnel and include the appropriate level of supporting documentation prior to being posted to the general ledger.  We have assessed the design and tested the operating effectiveness of the key controls over the Executive and Management Compensation Arrangements and conclude that the material weakness was effectively remediated at December 31, 2011.

Based on the implementation of the additional processes and internal controls discussed above and the subsequent testing of those internal controls for a sufficient period of time, our management has concluded that the material weaknesses identified above have been remediated. We will continue to monitor the effectiveness of these actions and will make any changes and take such other actions deemed appropriate given the circumstances.
 
 
Predecessor’s Material Weaknesses
 
Inventory Balances
 
Description of Material Weakness as of December 31, 2010
 
The Company 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.
 
Description of 2011 Remediation Actions
 
 
·
The material weakness in 2010 related to the inventory balance recorded on our predecessor’s books. Inventory is no longer a significant account balance for our Company; therefore, we have concluded that inventory does not represent a risk of misstatement that individually or in combination with others could result in material misstatement of the financial statements as of December 31, 2011.
 
Material Weaknesses as of December 31, 2011
 
Depreciation, Depletion and Amortization Calculation
 
Description of Material Weakness as of December 31, 2010
 
We did not maintain effective controls over the completeness and accuracy of the inputs with respect to the depreciation, depletion, and amortization calculation. Specifically, we did not develop detailed procedures for the accounting staff to follow in order to provide reasonable assurance that the inputs to the calculation are complete and accurate.
 
Description of 2011 Remediation Actions
 
 
·
We have updated our policies and procedures for the calculation of DD&A. Furthermore, we are in the process of developing detailed procedures which are followed by accounting staff to provide reasonable assurance that the inputs to the calculations are complete, are tied to supporting documentation and any resulting journal entries are reviewed by higher level accounting personnel and include the appropriate level of supporting documentation prior to being posted into the general ledger. Remediation efforts are ongoing and this material weakness continues to exist as of December 31, 2011.
 
Review of Specific Account Calculations
 
We did not maintain effective controls over the completeness and accuracy of certain calculations used in recording mark-to-market for derivatives expense, the general and administrative allocation and ad valorem taxes. Specifically, we did not maintain effective controls related to the detail review of these calculations.
 
The Company is currently considering appropriate remendiation actions and is developing a remediation plan for implementation during 2012.
 

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
 
As identified above, under "Remediated Material Weaknesses," there were changes in our 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 fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 

PART III
 
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

As is the case with many publicly traded partnerships, we do not directly employ officers, directors or employees.  Our operations and activities are managed by Quantum Resources Management, an affiliate of our general partner. References 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.
 
Name
  
Age
  
Position with our General Partner
Alan L. Smith
     49  
Chief Executive Officer and Director
John H. Campbell, Jr.
     54  
President, Chief Operating Officer and Director
Cedric W. Burgher
     51  
Chief Financial Officer
Gregory S. Roden
     53  
Vice President, Secretary and General Counsel
Lloyd V. DeLano
     61  
Chief Accounting Officer
Toby R. Neugebauer
     41  
Director
Donald E. Powell (1)
     70  
Director
Stephen A. Thorington (2)
     56  
Director
S. Wil VanLoh, Jr.
     41  
Director
Richard K. Hebert (3)
     60  
Director
Donald D. Wolf
     68  
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.
 
(3)
Member of the audit committee and the conflicts committee.


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

Alan L. Smith is the Chief Executive Officer and a member of the board of directors of our general partner. Mr. Smith also serves as a Venture Partner 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 GP, LLC, the entity controlling the Fund. We believe that Mr. Campbell’s extensive experience in the energy industry, particularly his background and experience in the engineering and operational aspects of exploration and production activities, bring important experience and skill to the board of directors.

Cedric W. Burgher is the Chief Financial Officer of our general partner.  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, LLC since 2008.  Mr. Burgher is a Chartered Financial Analyst (CFA).


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

Lloyd V. DeLano is the Chief Accounting Officer of our general partner. Mr. DeLano 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 2011, Mr. DeLano served as Senior Vice President and Chief Accounting Officer of The Meridian Resource Corporation for the past 18 years. Prior to that, Mr. DeLano served in various accounting and planning roles at Elf Aquitane, Cabot Corporation, A-S Energy and Shenandoah Oil Corporation. Mr. DeLano is a Certified Public Accountant.

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

Donald E. Powell serves on the board of directors of our general partner. 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 of directors.

Stephen A. Thorington serves 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 committee, conflicts committee, and board of directors.

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


Richard K. Hebert is a member of the board of directors of our general partner and is a member of our Audit Committee and Conflicts Committee.  Mr. Hebert is a Managing Member of Consolidated Oil & Gas, LLC and Consolidated Property Interests, LLC, both of which he co-founded in 2008-2009.  He also serves on the board of Forge Energy. Mr. Hebert has more than 35 years of experience in the upstream oil and gas industry. Mr. Hebert served as the Chairman and Chief Executive Officer of Devonshire Energy, as President, Chief Executive Officer, and Chief Operating Officer of Howell Corporation, and as the Chief Executive Officer of Voyager Energy Corp, which he co-founded, prior to Voyager being acquired by Howell.  Mr. Hebert also served in executive and managerial roles at Burlington Resources and managerial and technical roles at Mobil Oil, Inc. and Superior Oil, Inc.  He began his career in 1974 as a production and reservoir engineer with Amoco Production Company. Mr. Hebert’s industry and executive experiences enable him to make valuable contributions to our audit committee, conflicts committee, and board of directors.
 
Donald D. Wolf serves as the Chairman of the board of directors of our general partner. Previously, Mr. Wolf served as the Chief Executive Officer of Quantum Resources Management from 2006 until 2009 and he continues to serve as the Chief Executive Officer of the general partner of the Fund. Prior to serving as the Chief Executive Officer of Quantum Resources Management, Mr. Wolf served as President and Chief Executive Officer of Aspect Energy, LLC, from 2004 until 2006. Prior to joining Aspect, Mr. Wolf served as Chairman and Chief Executive Officer of Westport Resources Corporation from 1996 to 2004. Mr. Wolf has also served as President and Chief Operating Officer of United Meridian Corporation from 1994 to 1996; President and Chief Executive Officer of General Atlantic Resources, Inc. from 1981 to 1993; and Co-Founder and President of Terra Marine Energy Company from 1977 to 1981. He began his career in 1965 with Sun Oil Company in Calgary, Alberta, Canada, working in operations and land management. Following Sun Oil Company, he assumed land management positions with Bow Valley Exploration, Tesoro Petroleum Corp. and Southland Royalty Company from 1971 through 1977. Mr. Wolf currently serves as a director of the general partner of MarkWest Energy Partners, L.P., Enduring Resources, LLC, Laredo Petroleum, LLC, Ute Energy, LLC and Aspect Energy, LLC. Mr. Wolf also serves on the board of QA Global GP, LLC, the entity controlling the Fund. Mr. Wolf is a former director of the Independent Petroleum Association of Mountain States, or IPAMS. We believe that Mr. Wolf’s extensive experience in the energy industry, most notably in serving as Chief Executive Officer of Westport Resources Corporation for eight years, bring substantial experience and leadership skill to the board of directors.

Composition of the Board of Directors

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


Non-Management Executive Sessions and Unitholder Communications

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

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

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

Because we are a limited partnership, the listing standards of the NYSE do not require that we or our general partner have a majority of independent directors or a 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, Hebert and Powell satisfy the NYSE and SEC requirements for independence.
 
Audit Committee

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

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

The audit committee has the sole authority and responsibility to retain and terminate our independent registered public accounting firm, resolve disputes with such firm, approve all auditing services and related fees and the terms thereof and pre–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.
 
The Audit Committee oversees our financial reporting process on behalf of the Board. Management has the primary responsibility for the preparation of the financial statements and the reporting process, including the systems of internal control.

With respect to the consolidated financial statements for the year ended December 31, 2011, the Audit Committee reviewed and discussed the consolidated financial statements of QR Energy, LP and the quality of financial reporting with management and the independent registered public accounting firm. It also discussed with the independent registered public accounting firm the matters required to be discussed by Statement on Auditing Standards No. 61, as amended (AICPA, Professional Standards, Vol. 1, AU section 380), as adopted by the Public Company Accounting Oversight Board (PCAOB) in Rule 3200T. The Audit Committee also discussed with the independent registered public accounting firm its independence from QR Energy, LP and received from the independent registered public accounting firm the written disclosures and the letter from the independent registered public accounting firm complying with the applicable requirements of the PCAOB regarding the independent registered public accounting firm’s communications with the Audit Committee concerning independence.

Based on the reviews and discussions described above, the Audit Committee recommended to our Board that the consolidated financial statements of QR Energy, LP be included in the Annual Report on Form 10-K for the year ended December 31, 2011 for filing with the SEC.

Conflicts Committee

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


Meetings and Other Information

During 2011, the board of directors had ten regularly scheduled and special meetings, the audit committee had ten meetings, and the conflicts committee had eight meetings.  None of our directors attended fewer than 75% of the aggregate number of meetings of the board of directors and committees of the board on which the director served.
 
Our partnership agreement provides that the general partner manages and operates us and that, unlike holders of common stock in a corporation, unitholders only have limited voting rights on matters affecting our business or governance.  Accordingly, we do not hold annual meetings of unitholders.

Section 16(a) Beneficial Ownership Reporting Compliance

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

Based solely on a review of the copies of reports on Forms 3, 4 and 5 and amendments thereto furnished to us and written representations from the executive officers and directors of our general partner, we believe that during the year ended December 31, 2011 the officers and directors of our general partner and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a).

Corporate Code of Business Conduct and Ethics

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

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

Reimbursement of Expenses of Our General Partner

Our general partner does not receive any compensation for its management of our partnership. Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Under the terms of the services agreement between our general partner and Quantum Resources Management, 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 (our affiliate), 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.  Because over the course of 2011 we shared all of our named executive officers (as defined below) with the Fund, the service agreement sets forth rules about what portion of those executives’ pay and benefits is to be reimbursed by our general partner, and in turn by us.  The amount of money that our general partner reimburses Quantum Resources Management for these expenses is calculated based on the “Production Percentage”, which is calculated by dividing (i) the average daily production in MBoe/d for the Partnership by (ii) the total average combined daily production in MBoe/d for the Partnership and the Fund.  The Production Percentage for 2011 was 69.46%.  Note, however, that the amount of money paid to Quantum Resources Management by the general partner, and then in turn by us, in reimbursement for compensation expenses in 2011 is capped at the amount of the total administrative services fee under the Services Agreement for the year ended December 31, 2011.  The figures reported in the Summary Compensation Table below reflect the portion of the compensation expense accrued by us for the named executive officers’ services, calculated using the Production Percentage but prior to application of the cap on our reimbursement obligation.  As such, the amounts reported in the Summary Compensation Table may reflect larger figures than the cost actually incurred by us for the named executive officers’ services.  Please read “Certain Relationships and Related Party Transactions— Ownership in Our General Partner by the Management of the Fund—Services Agreement” for more information on the Services Agreement.

We commenced our business operations at the time of our initial public offering on December 22, 2010.   Following the initial public offering, our general partner’s board of directors typically has had responsibility and authority for compensation-related decisions for our named executive officers in respect of their service to us while Quantum Resources Management has responsibility and authority for compensation-related decisions for our named executive officers in respect of their service to the Fund and other entities.  All changes to compensation for the named executive officers with respect to services performed for us were approved by our general partner’s board of directors and Quantum Resources Management was directed to pay accordingly.    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.

Objectives of our Compensation Program

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


2011 Named Executive Officers

This compensation discussion and analysis, or CD&A, provides general information about the compensation paid to our Chief Executive Officer, Chief Financial Officer, and the three other most highly compensated 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 Position
Alan L. Smith
  
Chief Executive Officer
John H. Campbell, Jr.
  
President and Chief Operating Officer
Cedric W. Burgher
  
Chief Financial Officer
Gregory S. Roden
  
Vice President, Secretary and General Counsel
Lloyd V. DeLano
  
Chief Accounting Officer
 
Compensation Decisions for Fiscal 2011

Throughout 2011 until September 30, 2011, Mr. Burgher performed services for the Fund as interim Chief Financial Officer, in addition to those services he performed directly on our behalf, and was independently compensated for services provided to the Fund by the Fund.  Following September 30, 2011, Mr. Burgher’s services were dedicated exclusively to us.  Our general partner reimbursed Quantum Resources Management for Mr. Burgher’s base salary (currently $275,000), bonus, and cost of benefits and we, in turn, reimbursed our general partner for those payments. In 2011, decisions regarding the compensation paid to Mr. Burgher (including his base salary and additional pay received for his service to the Fund as interim chief Financial Officer) were made by Quantum Resources Management, other than Mr. Burgher’s 2011 bonus which was determined by our general partner’s board of directors.

Messrs. Roden and DeLano also performed services both for us and the Fund during 2011.  Quantum Resources Management had the responsibility and authority for compensation-related decisions (including base salary) for Messrs. Roden and DeLano during fiscal 2011; however, our general partner’s board of directors made decisions regarding their 2011 cash bonus awards and awards granted to them under our general partner’s long-term incentive plan (the “LTIP”), described below.  Our general partner reimbursed Quantum Resources Management for a portion of Messrs. Roden and DeLano’s base salary (currently each $250,000), cash bonus, and the cost of their benefits calculated using the Production Percentage which was 69.46%  for 2011, prior to the application of the cap of 3.5% of Adjusted EBITDA applied under the Services Agreement. Mr. DeLano was hired as our Chief Accounting Officer on July 18, 2011, to replace our previous Chief Accounting Officer, Howard Selzer, who resigned July 12, 2011.

Finally, Messrs. Smith and Campbell also performed services for both us and the Fund during 2011.  Quantum Resources Management had the responsibility and authority to set the base salary and benefits for Messrs. Smith and Campbell related to the services performed for us, our general partner’s board of directors had the authority to make grants under our general partner’s LTIP to Messrs. Smith and Campbell for services performed for us, and the executives’ compensation for services performed for the Fund was determined and paid by the sponsors of the Fund.  Messrs. Smith and Campbell’s salaries were set prior to 2011 at a level that allows them to be eligible to receive benefits under the Quantum Resources Management plans (for example, health and dental insurance plans).  Messrs. Smith and Campbell do not receive annual cash bonuses for the services they provide to us because their primary cash compensation is set and paid by the sponsors of the Fund.  Messrs. Smith and Campbell received grants under our general partner’s LTIP in 2011 in lieu of a higher base salary for the services provided to us.  Our general partner’s board of directors elected to grant restricted units to these executives rather than increase their base salary because restricted units have a stronger retentive benefit.


Annual Cash Bonus

We include an annual cash bonus as part of our compensation program because we believe this element of compensation helps to motivate management to achieve key operational objectives by rewarding the achievement of these objectives.  The annual cash bonus also allows us to be competitive from a total remuneration standpoint.  In 2011, our Chief Executive Officer made recommendations to our general partner’s board of directors regarding the level of annual bonus he felt appropriate for Messrs. Burgher, Roden, and DeLano for services provided during 2011.  Our general partner’s board of directors reviewed the recommendations made by our Chief Executive Officer and approved cash bonuses awarded to Messrs. Burgher, Roden and DeLano, in the amounts enumerated below.

The board of directors generally targets between 50% and 75% of base salary for performance deemed by our board of directors to be good and exceptional, respectively, with the possibility of no bonus for poor performance and higher for exceptional corporate or individual performance.   When determining the amounts of the cash bonuses awarded for 2011, the general partner’s board of directors, took into account our Chief Executive Officer’s recommendations as well as its belief that our executives’ efforts directly affected our success in 2011, in particular, by contributing to our achievement for the following milestones:

 
·
Our quarterly distributions increased from $0.4125 per unit to $0.475 per unit;
 
 
·
We successfully completed an acquisition of assets from the Fund in exchange for the new issuance of 16,666,667 convertible preferred units with a fair value of  $354,500,000;
 
 
·
We achieved reasonable strong operating performance within production guidance and maintained strong liquidity; and
 
 
·
We renegotiated our credit facility in connection with the acquisition of new assets from the Fund, increasing our borrowing base from $330,000,000 to $630,000,000.

In 2011, Mr. Burgher received a cash bonus of $197,037 (72% of base salary) paid by Quantum Resources Management that is reimbursable by our general partner under the Services Agreement.
 
In 2011, Mr. Roden received a cash bonus of $187,500 (75% of base salary) of which $130,243 reflects the portion of the cash bonus paid by Quantum Resources Management that is reimbursable by our general partner under the Services Agreement using the Production Percentage, prior to the application of the cap of 3.5% of Adjusted EBITDA applied under the Services Agreement.

In 2011, Mr. DeLano received a cash bonus of $78,125 (74% of base salary) of which $24,829  reflects the portion of the cash bonus paid by Quantum Resources Management that is reimbursable by our general partner under the Services Agreement using the Production Percentage and further pro rated based on his partial service for 2011 based on his employment commencement date of July 18, 2011, prior to the application of the cap of 3.5% of Adjusted EBITDA applied under the Services Agreement.

 In each of the cases of Messrs. Burgher, Roden and DeLano, the bonuses paid reflected the committee’s determination that their performances in accomplishing the milestones for 2011 described above were exceptional.

Messrs. Smith and Campbell were not paid cash bonuses in 2011 and no recommendations were made to our general partner’s board of directors in connection with their bonuses.

Compensation Consultant

To assist us in evaluating our compensation program for 2011 and 2012, our chief executive officer retained Longnecker & Associates, a compensation consulting firm, on our behalf, to review our proposed compensation programs designed to provide long term retention incentives to our named executive officers and those professional employees of Quantum Resources Management that provide services to us pursuant to the Services Agreement.  This information was used by us to obtain a general sense of the market levels of compensation paid by other companies in our industry and to establish compensation programs and awards that most effectively incentivize our executives to achieve our longer-term goals and can also be used as a tool to promote retention of our key employees required to provide a long term incentive to retain key employees.


The recommendations of Longnecker & Associates were taken into consideration in formulating the recommendations made to the board of directors of our general partner regarding compensation for Quantum Resources Management employees, including recommendations regarding the cash bonuses paid to Messrs. Burgher, Roden and DeLano.   With respect to bonuses and long-term incentive awards, our general partner’s board of directors did not establish performance metrics for our executive officers for 2011 in order to remain flexible in our compensation practices.  The general partner’s board of directors makes a subjective determination at the end of the fiscal year as to the appropriate compensation based on a recommendation from our chief executive officer and given their view of our performance for the year.

Long-Term Incentive Plan Awards

In conjunction with our initial public offering, our general partner adopted the LTIP.  Employees, officers (including each of our named executive officers), consultants and directors of our general partner and its affiliates (including Quantum Resource Management) who perform services for us are eligible to participate in the LTIP.  The LTIP allows for the grant of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards.  As of December 31, 2011, there were 1,486,357 common units that remain available for issuance under the LTIP.  

On March 9, 2011, the board of directors of our general partner granted each of Messrs. Smith and Campbell an award of 8,985 restricted units under the LTIP.  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 board of directors of our general partner decided to make this award to Messrs. Smith and Campbell because they did not receive a grant of restricted units associated with our initial public offering.  Further, our general partner’s board of directors elected to grant restricted units to these executives rather than increase their base salary because restricted units have a stronger retentive benefit.  Neither Messrs. Smith or Campbell are paid a base salary or cash bonus that is reimbursed by our general partner.  Since no base salary or cash bonus was paid to Messrs. Smith and Campbell, our general partner’s board of directors made a subjective determination in the first quarter of 2011 that an award of restricted units with a value of approximately $200,000 provided a combination of long term incentives and appropriate compensation for services provided by Messrs. Smith and Campbell on our behalf for 2011.

On November 1, 2011, the board of directors of our general partner granted Mr. DeLano an award of 6,164 restricted units under the LTIP.  These restricted units vest in equal one-third increments over a 36-month period (i.e., approximately 33.3% vests at each one-year anniversary of the date of grant, so that the restricted units will be 100% vested on November 1, 2014) provided Mr. DeLano 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.  The board of directors of our general partner decided to make this award to Mr. DeLano because (i) the board was making grants under the LTIP to other non-executive employees and (ii) he was an executive that had not received an award of restricted units (because he was hired in July of 2011) and the board wanted to utilize the award as a retention tool.  The award of 6,164 units was determined by our general partner’s board of directors because at the time of grant the value of this award was equal to approximately 50% of Mr. DeLano’s base salary, which was consistent with the target range of awards previously granted to other officers and managers comparable to Mr. DeLano’s position.

Awards of restricted units were not made to Messrs. Burgher and Roden, as these executives received such awards in conjunction with our initial public offering.

The restricted units granted to our named executive officers will also 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 the restricted units to the same extent as our unitholders receive cash distributions on our common units. Such distributions are paid to the named executive officer at the same time as cash distributions are paid to our common unitholders.  With respect to future grants under the LTIP, the board of directors of our general partner intends to continue to grant primarily restricted unit awards with UDRs under the plan.  These awards are intended to align the interests of key employees (including our named executive officers) with those of our unitholders.


Other Benefits

Quantum Resources Management does not maintain a defined benefit or pension plan for our named executive officers because it believes such plans primarily reward longevity rather than performance. Quantum Resources Management provides a basic benefits package to all of its employees that includes participation in a 401(k) plan and health, disability and life insurance. Employees that provide services to us pursuant to the Services Agreement, including our named executive officers, are entitled to the same basic benefits. In 2011, the Quantum Resource Management dollar-for-dollar matching contribution under the 401(k) plan was converted to a safe harbor dollar-for-dollar matching contribution on the first 3% of eligible compensation and a 50% company match on the next 2% of eligible compensation contributed to the plan, subject to the applicable contribution limits set forth in the Internal Revenue Code.  An additional discretionary employer contribution may also be made under the 401(k) plan on behalf of eligible employees who meet certain conditions and subject to certain limitations under applicable law; however, no such additional contributions were made during 2011.  

Compensation Expectations for 2012

In fiscal 2012, Mr. Burgher will devote all of his time to our business.  As a result, the board of directors of our general partner will have sole responsibility and authority for compensation-related decisions relating to Mr. Burgher.  Additionally our general partner will reimburse Quantum Resources Management for the full amount of Mr. Burgher’s base salary, bonus and benefit cost and we, in turn, will reimburse our general partner for those payments.  All payments for Mr. Burgher’s salary, bonus, and cost of other benefits made by our general partner to Quantum Resources Management are subject to the cap equal to 3.5% of Adjusted EBITDA pursuant to 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.  Additionally, to further incentivize Mr. Burgher, 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 by the owners of our general partner will not be an expense reimbursed by our general partner or us under the Services Agreement.

We expect that the compensation of our named executive officers for fiscal 2012 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 our named executive officers’ impact on our partnership’s performance.  The performance metrics governing incentive compensation will not be tied in any way to the performance of entities other than our partnership (such as Quantum Resources Management, the Fund, Quantum Energy Partners, or any of our other affiliates).  We believe this pay-for-performance approach generally aligns the interests of our named executive officers with those of our unitholders and at the same time enables us to maintain a lower level of base overhead in the event our operating and financial performance fails to meet expectations.

Tax Deductibility of Compensation

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

 
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, 2011.  The amount of money paid to Quantum Resources Management by the general partner, and then in turn by us in reimbursement for compensation expenses in 2011 is capped at the amount of the total administrative services fee under the Services Agreement for the year ended December 31, 2011.  The figures reported in the Summary Compensation Table below reflect the portion of the compensation expense accrued by us for the named executive officers’ services, calculated using the Production Percentage but prior to application of the cap on our reimbursement obligation.  As such, the amounts reported in the Summary Compensation Table may reflect larger figures than the cost actually incurred by us for the named executive officers’ services.  Please read “Certain Relationships and Related Party Transactions— Ownership in Our General Partner by the Management of the Fund—Services Agreement” for more information on the Services Agreement.  Please also note that 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.  Consequently, the figures reported in the table below for 2010 were calculated by multiplying total compensation paid to the named executive officers for the period beginning on December 22, 2010 through December 31, 2010 by the 2010 Production Percentage 29.96%.
 
 
 
 Name
  
 
 
 Year
  
 
 
Salary (1)
    
 
 
Bonus(2)(3)
    
(4)
Stock
Awards
    
 
All Other (5)
Compensation
    
 
Total
Compensation
  
Alan L. Smith
  
2011
   $ 34,732     $ -     $ 200,006     $ 12,970     $ 247,708  
Chief Executive Officer
  
2010
   $ 410     $ -     $ -     $ -     $ 410  
John H. Campbell, Jr.
  
2011
   $ 34,732     $ -     $ 200,006     $ 10,471     $ 245,209  
President and Chief Operating Officer
  
2010
   $ 410     $ -     $ -     $ -     $ 410  
Cedric W. Burgher
  
2011
   $ 275,000     $ 197,937     $ -     $ 21,993     $ 494,930  
Chief Financial Officer
  
2010
   $ 7,535     $ 1,413     $ 1,702,550     $ -     $ 1,711,498  
Gregory S. Roden
  
2011
   $ 173,658     $ 130,243     $ -     $ 26,597     $ 330,498  
Vice President, Secretary and General Counsel
  
2010
   $ 1,847     $ 1,847     $ 200,300     $ 129     $ 204,123  
Lloyd V. DeLano
  
2011
   $ 73,737     $ 54,268     $ 125,006     $ 9,457     $ 262,468  
Chief Accounting Officer
  
 
                                        

(1)
For all named executive officers other than Mr. Burgher and Mr. DeLano, the figures in this column reflect the portion of the base salaries paid by Quantum Resources Management to those of our named executive officers referenced above that is reimbursable by our general partner under the Services Agreement (allocated based on the Production Percentage, which was 69.46%  for 2011), prior to the application of the cap of 3.5% of Adjusted EBITDA applied under the Services Agreement.  For Mr. Burgher, in 2011 the figure in this column represents his base salary paid by Quantum Resources Management and reimbursed by our general partner. For Mr. DeLano, the figure reflected in this column reflects the portion of the base salary paid by Quantum Resources Management that is reimbursable by our general partner under the Services Agreement allocated based on the Production Percentage, which was 69.46% for 2011 and further pro rated to reflect his partial service for 2011 based on his employment commencement date of July 18, 2011, prior to the application of the cap of 3.5% of Adjusted EBITDA applied under the Services Agreement.

(2)
For Mr. Roden and DeLano, the figures in this column reflect the portion of the annual cash bonus paid by Quantum Resources Management that is reimbursable by our general partner, and in turn by us, under the Services Agreement (allocated based on the Production Percentage, which was 69.46%  for 2011), prior to the application of the cap of 3.5% of Adjusted EBITDA applied under the Services Agreement.  Mr. DeLano’s bonus is further pro rated based on his partial service for 2011 based on his employment commencement date of July 18, 2011.  For Mr. Burgher, in 2011 the figure in this column represents the portion of his annual cash bonus paid by Quantum Resources Management and reimbursed by our general partner.

(3)
Reflects the aggregate grant date fair value of restricted unit awards granted under the LTIP calculated by multiplying the number of restricted units granted to each executive by the closing price of our common units on the date of grant ($22.26 with respect to the grants made to Messrs. Smith and Campbell on March 9, 2011 and $20.28 with respect to the grant made to Mr. DeLano on November 1, 2011).  These values were computed in accordance with FASB ASC Topic 718.  See Note 11 to our consolidated financial statements for fiscal 2011 for additional detail regarding assumptions underlying the value of these equity awards.

(4)
The figures in this column reflect the portion of (i) matching contributions under the Quantum Resources Management 401(k) plan, and (ii) unused vacation paid by Quantum Resources Management to those our named executive officers referenced above that is reimbursable by our general partner under the Services Agreement (other than for Mr. Burgher who is allocated at 100%, each other executive is allocated based on the Production Percentage, which was 69.46% for 2011), prior to the application of the cap of 3.5% of Adjusted EBITDA applied under the Services Agreement. Pursuant to Rule 402(c)(2)(ix), distributions paid to each executive on unvested LTIP units are not included in the total Other Compensation reported, however, Mr. Smith and Mr. Campbell each received $15,386 in such distributions, Mr. Burgher received $110,599 in such distributions, and Mr. Roden received $13,012 in such distributions


  Grants of Plan-Based Awards for Fiscal 2011

The following table sets forth certain information with respect to grants of restricted units to our named officers in fiscal 2011.

Name
  
Grant Date
  
Number of Shares
of Stock or Units
    
Grant Date Fair Value of
Stock and Option Awards (1)
  
Alan L. Smith
  
3/9/2011
     8,985     $ 181,138  
John H. Campbell , Jr.
  
3/9/2011
     8,985     $ 181,138  
Lloyd V. DeLano
  
11/1/2011
     6,164     $ 124,266  
 
(1)
Reflects the aggregate grant date fair value of restricted unit awards granted under the LTIP calculated by multiplying the number of restricted units granted to each executive by the closing price of our common units on the date of grant ($22.26 with respect to the grants made to Messrs. Smith and Campbell on March 9, 2011 and $20.28 with respect to the grant made to Mr. DeLano on November 1, 2011).  These values were computed in accordance with FASB ASC Topic 718.  See Note 11 to our consolidated financial statements for fiscal 2011 for additional detail regarding assumptions underlying the value of these equity awards.
 
Narrative Description to the Summary Compensation Table and the Grant of Plan-Based Awards Table for the 2011 Fiscal Year
 
We have not entered into employment agreements with any of our named executive officers. 

On March 9, 2011, the board of directors of our general partner granted each of Messrs. Smith and Campbell an award of 8,985 restricted units under the LTIP.  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.  

On November 1, 2011, the board of directors of our general partner granted Mr. DeLano an award of 6,164 restricted units under the LTIP.  These restricted units vest in equal one-third increments over a 36-month period (i.e., approximately 33.3% vests at each one-year anniversary of the date of grant, so that the restricted units will be 100% vested on November 1, 2014) provided Mr. DeLano 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.  

Awards of restricted units were not made to Messrs. Burgher and Roden in 2011.


Outstanding Equity Awards at Fiscal Year-End

The following table sets forth certain information with respect to outstanding equity awards at December 31, 2011.

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
     8,985     $ 181,138  
John H. Campbell, Jr.
     8,985     $ 181,138  
Cedric W. Burgher (1), (3)
     66,667     $ 1,344,007  
Gregory S. Roden (1)
     6,667     $ 134,407  
Lloyd V. DeLano (4)
     6,164     $ 124,266  
 
(1)
Messrs. Smith and Campbell were each granted an award of 8,985 restricted units on March 9, 2011. These restricted units vest in equal one-third increments over a 36-month period.  As such, restricted units under each award will vest with respect to 2,995 restricted units on March 9, 2012; 2,995 restricted units on March 9, 2013; and 2,995 restricted units on March 9, 2014, subject to continued service.

(2)
Messrs. Burgher and Roden were each granted an award of 10,000 restricted units on December 22, 2010.  These restricted units vest in equal one-third increments over a 36-month period.  As such, 3,333 restricted units from each of these awards vested on December 22, 2011.  The remaining unvested units under each award will vest with respect to 3,333 restricted units on December 22, 2012 and 3,334 restricted units on December 22, 2013, subject to continued service.

(3)
Mr. Burgher was granted an award of 75,000 restricted units on December 22, 2010.  These restricted units vest in equal one-fifth increments over a 60-month period.  As such, 15,000 restricted units vested on December 22, 2011.  The remaining unvested units will vest with respect to 15,000 restricted units on each of December 22, 2012, December 22, 2013, December 22, 2014, and December 22, 2015.
 
(4)
Mr. DeLano was granted an award of 6,164 restricted units on November 1, 2011.  These restricted units vest in equal one-third increments over a 36-month period.  As such, restricted units under this award will vest with respect to 2,054 restricted units on November 1, 2012; 2,055 restricted units on November 1, 2013; and 2,055 restricted units on November 1, 2014, subject to continued service.

(5)
The market value of unvested restricted units listed in this column was calculated by multiplying the closing price of our common units on December 31, 2011, which was $20.16, by the number of restricted units outstanding.

Option Exercises and Stock Vested

The following table sets forth certain information with respect to restricted units vested during 2011.   

Name
  
Number of
LTIP Units
Acquired on Vesting
    
Value Realized
on Vesting (1)
  
Cedrick W. Burgher (2)
     13,750     $ 274,862  
Gregory S. Roden
     3,333     $ 63,960  
 
 
(1)
The dollar amount realized upon vesting of restricted units was calculated by multiplying the number of restricted units that vested by the market value of the underlying units on the vesting date.  Because restricted units in the amount of 3,333 for Mr. Roden and 18,333 for Mr. Burgher vested on December 22, 2011, the market value used to calculate the value realized on vesting for those units was $19.99, the closing price of our units on that date.  The value realized on vesting reported above represent the gross number of units received by the executives on vesting, prior to the net withholding of units for purposes of fulfilling federal and state income tax obligations.
 

Pension Benefits

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

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.

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 30, 2011 and using our closing stock price on that date of $20.16. 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
   $ 181,138     $ 181,138  
John H. Campbell, Jr.
   $ 181,138     $ 181,138  
Cedric W. Burgher
   $ 1,344,007     $ 1,344,007  
Gregory S. Roden
   $ 134,407     $ 134,407  
Lloyd V. Delano
   $ 124,266     $ 124,266  

(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, 2011, $20.16, 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.  Directors who have a vested ownership interest in our general partner do not receive compensation for services provided to us as directors.  We use a combination of cash and unit-based incentive compensation to attract and retain qualified candidates to serve on our general partner’s board of directors.  In setting director compensation, we consider the significant amount of time that directors expend in fulfilling their duties to us as well as the skill level we require of members of the board.  Each director who is not an officer or employee of our general partner or its affiliates receives an annual fee, paid in cash, and an award of LTIP units as compensation for his or her services as a director to our general partner.  Directors do not receive additional compensation for serving on the audit or conflicts committees of the board of directors of our general partner or additional fees for each meeting attended.  Each non-employee director is reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors, committees.  Each director is also fully indemnified by us for actions associated with being a director to the full extent permitted under Delaware law.


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

During 2011, our general partner paid 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.  During 2011, our general partner paid Mr. Hebert $37,500 in cash and 1,817 units under the LTIP in annual compensation for his services during the second half of 2011 as a director of our general partner which represents a pro rated amount of a full year of director compensation based on Mr. Hebert’s service for the last half of 2011.  As the LTIP units awarded to the directors of our general partner’s board of directors are considered part of their compensation for services performed on our behalf in 2011 and not as a long term retention incentive, the LTIP units vested immediately upon issuance.  No additional compensation or perquisites were awarded to the directors of our general partner other than the fees and LTIP units described above.
 
The table below includes compensation paid to our non-employee directors for their services during 2011.  Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation for their services as a director of our general partner and, as such, are not included in the table below.

Name
(a)
  
Fees Earned or Paid in Cash
($)(b)
    
Stock Awards
($)(c)(1)
    
Option Awards
($)(d)
    
Non-Equity Incentive
Plan Compensation
($)(e)
    
Change in
Pension Value
And
Nonqualified
Deferred
Compensation Earnings
($)(f)
    
All Other
Compensation
($)(g)
    
Total
($)(h)
  
Donald E. Powell
     75,000       75,750       -       -       -       -       150,750  
Stephen A. Thorington
     75,000       75,750       -       -       -       -       150,750  
Richard K. Hebert
     37,500       37,467       -       -       -       -       74,967  
Donald D. Wolf
     200,000       -       -       -       -       -       200,000  

 
(1)
Reflects the aggregate grant date fair value of unit awards granted under the LTIP calculated by multiplying the number of units granted to each director by the closing price of our common units on the date of grant ($20.20 with respect to the grants made to Messrs. Powell and Thorington on January 4, 2011 and $20.62 with respect to the grant made to Mr. Hebert on July 1, 2011).   These values were computed in accordance with FASB ASC Topic 718.  See Note 11 to our consolidated financial statements for fiscal 2011 for additional detail regarding assumptions underlying the value of these equity awards. LTIP equity awards for the independent directors were decided upon by the members of our general partner.


The table below reflects the aggregate number of units held by each director at fiscal year-end 2011.

Name
  
Units Owned at Year-end 2011
Donald E Powell
  
10,750
Stephen A. Thorington
  
23,750
Richard K. Hebert
  
7,017
Donald D. Wolf
  
0

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.

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of December 31, 2011:

 Plan Category
  
Outstanding
restricted units as of
 December 31, 2011
    
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, 2011
  
Equity compensation plans not approved by unitholders (1)
     271,364       N/A       1,486,357  
Long-term incentive plan
                        

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

As of December 31, 2011, the following table sets forth the beneficial ownership of our common, subordinated, general partner and convertible preferred units that are owned by:

 
·
Each person beneficially owned more than 5% of the then outstanding units;
 
 
·
Each director and director nominee of our General Partner;
 
 
·
Each named executive officer of our General Partner; and
 
 
·
All directors, director nominees and executive officers of our general partner as a group.

Name of
Beneficial Owner (1)
  
Common Units to be Beneficially Owned (2)
    
Percentage of Common Units to be Beneficially Owned
    
Subordinated Units to be Beneficially Owned
    
Percentage of Subordinated Units to be Beneficially Owned
    
Preferred Class C Units to be Beneficially Owned
    
Percentage of Preferred Class C Units to be Beneficially Owned
  
The Fund
     11,297,737       39.5 %     7,145,866       100.0 %     16,666,667       100.0 %
Donald D. Wolf (6)
     -       0.0 %     -       0.0 %     -       0.0 %
Alan L. Smith (6), (7), (8), (9)
     11,356,722       39.5 %     7,145,866       100.0 %     16,666,667       100.0 %
John H. Campbell, Jr. (6), (7), (8)
     11,306,722       39.5 %     7,145,866       100.0 %     16,666,667       100.0 %
Cedric W. Burgher (3)
     85,917       0.1 %     -       0.0 %     -       0.0 %
Gregory S. Roden (4)
     12,000       0.1 %     -       0.0 %     -       0.0 %
Lloyd V. DeLano (5)
     6,164       0.1 %     -       0.0 %     -       0.0 %
Toby R. Neugebauer (6), (7)
     11,297,737       39.5 %     7,145,866       100.0 %     16,666,667       100.0 %
S. Wil VanLoh (6), (7)
     11,297,737       39.5 %     7,145,866       100.0 %     16,666,667       100.0 %
Donald E. Powell (10)
     5,750       0.1 %     -       0.0 %     -       0.0 %
Stephen A. Thorington (10), (11)
     23,750       0.1 %     -       0.0 %     -       0.0 %
Richard K. Hebert (12)
     7,017       0.1 %     -       0.0 %     -       0.0 %

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

 
(2)
Includes common units that were awarded as LTIP units and common units purchased in the directed unit program at the closing of the IPO.

 
(3)
Includes 75,000 units issued to Mr. Burgher under the LTIP program upon the completion of the IPO (the “IPO units”), 10,000 units issued to Mr. Burgher under the LTIP program as part of his 2010 compensation (less 4,583 units withheld to cover the combined withholding tax occurring upon the vesting of 18,333  LTIP units on December 22, 2011) 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)
These units were awarded to Mr. DeLano under the LTIP program in connection with the consummation of the dropdown.

 
(6)
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, 6,533,194  subordinated units and 15,066,277 convertible preferred units;
 
 
·
QRB owns 186,283 common units, 117,825 subordinated units and 453,041 convertible preferred units;
 
 
·
QRC owns 330,670 common units, 209,150 subordinated units and 478,604 convertible preferred units;
 
 
·
QAB owns 3,802 common units, 2,405 subordinated units and 9,246 convertible preferred units;
 
 
·
QAC owns  6,748 common units, 4,268 subordinated units and 16,412 convertible preferred units;
 
 
·
Black Diamond owns 441,142 common units, 279,024 subordinated units and 643,087 convertible preferred units;

 
 
·
Three directors of our general partner, Messrs. Wolf, Neugebauer and VanLoh, and two directors and executive officers of our general partner, Messrs. Smith and Campbell, are also members of the board of directors of HoldCo GP, and as such, are entitled to vote on decisions, or to direct to vote and to dispose, or to direct the disposition of, the common units, subordinated units and Class C preferred 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, subordinated units and convertible preferred units held by the Fund.
 
 
(7)
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.

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

 
(9)
Includes 50,000 common units acquired by Mr. Smith under the directed unit program.

 
(10)
Includes 3,750 fully vested units awarded to each Mr. Powell and Mr. Thorington under the LTIP program upon their appointment as directors of the General Partner.

 
(11)
Includes 20,000 common units acquired by Mr. Thorington under the directed unit program.

 
(12)
Includes 1,817 fully vested units awarded to Mr. Hebert under the LTIP program upon his appointment as a director of the General Partner.
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Ownership in Our General Partner by the Management of the Fund

As of December 31, 2011, entities controlled by affiliates of the Fund owned our general partner and a 67.0% limited partner interest in the Partnership from its ownership in our common units, subordinated units, and Preferred Units.  In addition, the general partner owns a 0.1% general partner interest in the Partnership, represented by 35,729 general partner units.
 
Contracts with the Fund and Its Affiliates
 
Our general partner has entered into agreements with the Fund and its affiliates.  The following is a description of those agreements.
 
Services Agreement
 
On December 22, 2010, in connection with the closing of the IPO, our general partner entered into a Services Agreement (the “Services Agreement”) with Quantum Resources Management, pursuant to which Quantum Resources Management will provide the administrative and acquisition advisory services necessary to allow our general partner to manage, operate and grow our business. Under the Services Agreement, from the closing of the IPO through December 31, 2012, Quantum Resources Management 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 Quantum Resources Management incurs in its performance under the Services Agreement and we will reimburse our general partner for such payments it makes to Quantum Resources Management. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated by Quantum Resources Management to its affiliates. During the period from the closing of the IPO through December 31, 2010, and for the year ended December 31, 2011, we incurred $0.1 million and $2.5 million for the administrative services fee under the Services Agreement.
 
 
Omnibus Agreement
 
On December 22, 2010, in connection with the closing of the IPO, we entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among the Partnership, our general partner, OLLC, the Fund Entities, the Predecessor and QA Global.
 
Under the terms of the Omnibus Agreement, the Fund Entities will offer us the first opportunity to purchase properties that it may offer for sale, so long as the properties consist of at least 70% proved developed producing reserves. The 70% threshold is a value-weighted determination made by the Fund Entities. Additionally, the Fund Entities will allow us to participate in at least 25% of any acquisition opportunity to the extent that it invests any of the remaining $193.2 million of its unfunded committed equity capital and so long as at least 70% of the allocated value of such acquisition opportunity is attributable to proved developed producing reserves. 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 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 for five years after the date of the Omnibus Agreement.
 
The Omnibus Agreement provides that the Fund Entities will indemnify us in connection with those assets contributed to us at the closing of the IPO against: (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 IPO. The Fund indemnification obligation will (i) survive for one year after the closing of the 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 Entities against certain potential environmental claims, losses and expenses associated with the operation of our business that arise in connection with those assets contributed to us at the closing of the IPO after the consummation of the IPO.

Long–Term Incentive Awards / Plan
 
On December 22, 2010, in connection with the closing of the IPO, the board of directors of the general partner adopted the QRE GP, LLC Long Term Incentive Plan (the “LTIP”) for employees, officers, consultants and directors and consultants of the general partner and those of its affiliates, including Quantum Resources Management, who perform services for us. The LTIP consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the LTIP is to provide additional incentive compensation to employees providing services to us and to align the economic interests of such employees with the interests of our unitholders. The LTIP limits the number of common units that may be delivered pursuant to awards under the plan to 1.8 million units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. As of December 31, 2011, 271,364 restricted unit awards with a grant date fair value of $4.8 million had been granted under the LTIP.

Purchase and Sale Agreement

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

In exchange for the Transferred Properties, we assumed $227.0 million in debt from the Fund, which was repaid at closing and issued to the Fund 16,666,667 unregistered Class C Convertible Preferred Units (“Preferred Units”). The Preferred Units will receive a preferred quarterly distribution of $0.21 per Preferred Unit equal to a 4.0% annual coupon on the par value of $21.00, for the first three years following the date of issuance. After three years, the quarterly cash distribution will be equal to the greater of (a) $0.475 per Preferred Unit or (b) the cash distribution payable on each of our common units for such quarter. The Preferred Units are convertible, subject to certain limitations, into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment.
 
Registration Rights Agreement
 
In connection with the acquisition of the Transferred Properties, on October 3, 2011, we entered into a Registration Rights Agreement with the Fund (the “Registration Rights Agreement”), which granted certain registration rights to the Fund, including rights to (a) cause the Partnership to file with the SEC up to five shelf registration statements under the Securities Act for the resales of the common units to be issued upon conversion of the Preferred Units, and in certain circumstances, the resales of the Preferred Units, and (b) participate in future underwritten public offerings of the our common units.

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

Distributions of Available Cash to Our General Partner and Affiliates

We will generally make cash distributions to our common and subordinated unitholders and general partner pro rata, including our general partner and our affiliates. As of December 31, 2011, our general partner and its affiliates held 11,297,737 common units, all of the preferred and subordinated units and 35,729 general partner units. We distributed less than $0.1 million to our general partner during the year ended December 31, 2011. Preferred units receive a separate cash distribution in accordance with our Partnership Agreement.
 
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 our general partner selected PricewaterhouseCoopers LLP, an independent registered public accounting firm, to audit our consolidated financial statements for the year ended December 31, 2011.  The audit committee’s charter requires the audit committee to approve in advance all audit and non–audit services to be provided by our independent registered public accounting firm.  All services reported in the audit, audit–related, tax and all other fees categories below with respect to this Annual Report on Form 10–K for the year ended December 31, 2011 were approved by the audit committee.

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

   
Partnership
    
Predecessor
  
   
2011
    
2010 (3)
    
2010 (3)
  
Audit Fees (1)
   $ 1,042     $ -     $ 1,492  
Audit - related fees
     -       -       -  
Tax fees
     252       -       -  
All other fees (2)
     -       -       3  
Total fees paid to PwC
   $ 1,294     $ -     $ 1,495  

 
(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 and registration 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.


PART IV
 
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

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

(a)(2) Financial Statement Schedules

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

(a)(3) Exhibits

Exhibit Number
    
Description
3.1
  
—
Certificate of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.2
  
—
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
  
—
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, dated as of October 3, 2011 (Incorporated herein by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
3.5
  
—
Certificate of Formation of QRE GP, LLC (Incorporated by reference to Exhibit 3.4 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.6
  
—
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).
3.7
  
—
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).
3.8
  
—
Amended and Restated Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
4.1
+
—
Form of Restricted Unit Agreement under the QRE GP, LLC Long-Term Incentive Plan (Incorporated by reference to Exhibit 4.4 of the Partnership’s Registration Statement on Form S-8 (File No. 333-171333) filed on December 22, 2010).
4.2
  
—
Registration Rights Agreement, dated as of October 3, 2011, by and among QR Energy, LP, Quantum Resources A1, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC (Incorporated herein by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
10.1
  
—
Stakeholders’ Agreement, by and among QR Energy, LP, Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP and QAC Carried WI, LP, and Black Diamond Resources, LLC, dated as of September 29, 2010 (Incorporated by reference to Exhibit 10.8 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).

 
10.2
  
—
Omnibus Agreement by and among QR Energy, LP, QRE GP, LLC, Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources, C, LP, QAB Carried WI, LP, QAC Carried WI, LP, Black Diamond Resources, LLC, QA Holdings, LP and QA Global GP, LLC, dated December 22, 2010 (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
10.3
  
—
Services Agreement by and among QR Energy, LP, QRE GP, LLC, QRE Operating, LLC and Quantum Resources Management, LLC dated December 22, 2010 (Incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
10.4
  
—
Credit Agreement by and among QR Energy, LP, QRE GP, LLC, QRE Operating, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent, JPMorgan Chase Bank, N.A. as Syndication Agent, Royal Bank of Canada, The Royal Bank of Scotland plc and Toronto Dominion (New York) LLC, as Documentation Agents and the other lenders party thereto, dated as of December 22, 2010 (Incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
10.5
  
—
First Amendment to the Credit Agreement, dated as of October 3, 2011, by and among QR Energy, LP, QRE GP, LLC, QRE Operating, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent and the other lenders party thereto (Incorporated herein by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
10.6
  
—
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).
10.7
+
—
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).
10.8
  
—
Purchase and Sale Agreement, dated as of September 12, 2011, by and among QR Energy, LP, QRE Operating, LLC, Quantum Resources A1, LP, QAB Carried WI, LP, QAC Carried WI, LP, and Black Diamond Resources, LLC (Incorporated herein by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed September 12, 2011).
21.1*     List of Subsidiaries of QR Energy, LP
23.1*     Consent of PricewaterhouseCoopers LLP
23.2*     Consent of Miller and Lents, Ltd.
31.1*    
Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
31.2*    
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
32.1* *   Certification of Chief Executive Officer Pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2* *   Certification of Chief Financial Officer Pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*     Report of Miller and Lents, Ltd
99.2* *   Press release of QR Energy, LP issued March 15, 2012

* Filed as an exhibit to this Annual Report on Form 10-K.
** Furnished as an exhibit to this Annual Report on Form 10-K.
*** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under those sections.
+ Management contracts or compensatory plans or arrangements
 

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
QR Energy, LP
  
 
(Registrant)
  
       
Date: March 15, 2012
By:
QRE GP, LLC, its general partner
  
 
By:
 /s/ Cedric W. Burgher
  
   
Cedric W. Burgher
  
   
Chief Financial Officer
  

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 15, 2012.

     Signature
  
Title  (Position with QRE GP, LLC)
  
Date
         
/s/ Alan L Smith
  
Chief Executive Officer and Director
  
March 15, 2012
Alan L. Smith
  
 (Principal Executive Officer)
    
         
/s/ John H. Campbell, Jr.
  
President, Chief Operating Officer and Director
  
March 15, 2012
John H. Campbell, Jr.
        
         
/s/ Cedric W. Burgher
  
Chief Financial Officer
  
March 15, 2012
Cedric W. Burgher
  
(Principal Financial Officer)
    
         
/s/ Gregory S. Roden
  
Vice President, Secretary and General Counsel
  
March 15, 2012
Gregory S. Roden
        
         
/s/ Lloyd V. DeLano
  
Chief Accounting Officer
  
March 15, 2012
Lloyd V. DeLano
  
(Principal Accounting Officer)
    
         
/s/ Richard K. Hebert
  
Director
  
March 15, 2012
Richard K. Hebert
        
         
/s/ Toby R. Neugebauer
  
Director
  
March 15, 2012
Toby R. Neugebauer
        
         
/s/ Donald E. Powell
  
Director
  
March 15, 2012
Donald E. Powell
        
         
/s/ Stephen A. Thorington
  
Director
  
March 15, 2012
Stephen A. Thorington
        
         
/s/ S. Wil VanLoh, Jr.
  
Director
  
March 15, 2012
S. Wil VanLoh, Jr.
        
         
/s/ Donald D. Wolf
  
Chairman of the Board
  
March 15, 2012
Donald D. Wolf
        
 
 
INDEX TO FINANCIAL STATEMENTS
 
QR ENERGY, LP AUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
Reports of Independent Registered Public Accounting Firm
   F-2  
       
Consolidated Balance Sheets as of December 31, 2011 and 2010
   F-4  
       
Consolidated Statements of Operations for the Year ended December 31, 2011, the Periods from December 22, 2010 to December 31, 2010, from January 1, 2011 to December 21, 2010 and the Year ended December 31, 2009
   F-5  
       
Consolidated Statements of Changes in Partners' Capital for the Year ended December 31, 2011 and the Period from  December 22, 2010 to December 31, 2010
   F-6  
       
Consolidated Statement of Changes in Partners' Capital for the Period from January 1, 2010 to December 21, 2010 and the Year ended December 31, 2009
   F-7  
       
Consolidated Statements of Cash Flows for the Year ended December 31, 2011, the Periods from December 22, 2010 to December 31, 2010, from January 1, 2011 to December 21, 2011 and the Year ended December 31, 2009
   F-8  
       
Notes to Consolidated Financial Statements
   F-9  

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors of QRE GP, LLC
and the Unitholders of QR Energy, LP

In our opinion, the accompanying consolidated balance sheets as of December 31, 2011 and 2010 and the related consolidated statements of operations, changes in partners' capital and cash flows for the year ended December 31, 2011 and the period from December 22, 2010 to December 31, 2010 present fairly, in all material respects, the financial position of QR Energy, LP and its subsidiary (the "Partnership") at December 31, 2011 and 2010, and the results of their operations and their cash flows for the year ended December 31, 2011 and the period from December 22, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because material weaknesses in internal control over financial reporting related to (i) the completeness and accuracy of the inputs with respect to the depreciation, depletion, and amortization calculation and (ii) the completeness and accuracy of certain calculations used in recording derivatives mark to market, the general and administrative allocation and ad valorem taxes existed as of that date.  A material weakness is a deficiency, or a combination of 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 material weaknesses referred to above are described in Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A.  We considered these material weaknesses in determining the nature, timing, and extent of audit tests applied in our audit of the 2011 consolidated financial statements, and our opinion regarding the effectiveness of the Partnership’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.  The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in management's report referred to above.  Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits (which was an integrated audit in 2011).  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
 
/s/ PricewaterhouseCoopers LLP
 
Houston, Texas
 
March 15, 2012
 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of QRE GP, LLC
and the Unitholders of QR Energy, LP

In our opinion, the accompanying consolidated statements of operations, changes in partners' capital and cash flows for the period from January 1, 2010 to December 21, 2010 and the year ended December 31, 2009 present fairly, in all material respects, the results of operations and cash flows of QA Holdings, LP and its subsidiaries (the "Predecessor") for the period from January 1, 2010 to December 21, 2010 and the year ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the 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.
 
 
/s/ PricewaterhouseCoopers LLP
 
Houston, Texas
 
May 4, 2011
 

QR ENERGY, LP
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit amounts)

   
December 31,
    
December 31,
  
   
2011
    
2010
  
ASSETS
            
Current assets:
            
Cash and cash equivalents
   $ 17,433     $ 2,195  
Accounts receivable: oil and gas sales
     32,263       3,014  
Due from affiliate
     3,734       -  
Due from general partner
     -       715  
Derivative instruments
     32,683       9,887  
Prepaid and other current assets
     249       1,283  
Total current assets
     86,362       17,094  
Noncurrent assets:
                
Oil and gas properties, using the full cost method of accounting
     975,182       892,649  
Gas processing equipment
     865       109  
Less accumulated depreciation, depletion, amortization
     (80,484 )     (2,130 )
Total property and equipment, net
     895,563       890,628  
Derivative instruments
     70,570       26,415  
Deferred taxes
     290       1,100  
Deferred financing costs, net of amortization
     4,279       3,478  
Total noncurrent assets
     970,702       921,621  
Total assets
   $ 1,057,064     $ 938,715  
LIABILITIES AND PARTNERS' CAPITAL
                
Current liabilities:
                
Due to affiliates
   $ -     $ 442  
Current portion of asset retirement obligations
     348       4,166  
Derivative instruments
     9,569       10,886  
Accrued and other liabilities
     50,027       8,021  
Total current liabilities
     59,944       23,515  
Noncurrent liabilities:
                
Long-term debt
     500,000       452,000  
Derivative instruments
     16,906       46,801  
Asset retirement obligations
     65,353       39,248  
Deferred taxes
     20       -  
Total noncurrent liabilities
     582,279       538,049  
Commitments and contingencies (See Note 8)
                
Partners' capital:
                
Predecessor's capital
     -       179,546  
Class C converible preferred unitholders (16,666,667 and zero units issued and outstanding as of December 31, 2011 and 2010)
     358,138       -  
General partner (35,729 units issued and outstanding as of December 31, 2011 and 2010)
     546       708  
Public common unitholders (17,292,279 and 15,000,000 units issued and outstanding as of December 31, 2011 and 2010)
     241,306       276,723  
Affiliated common unitholders (11,297,737 units issued and outstanding as of December 31, 2011 and 2010)
     (113,414 )     (48,898 )
Subordinated unitholders (7,145,866 units issued and outstanding as of December 31, 2011 and 2010)
     (71,735 )     (30,928 )
Total partners' capital
     414,841       377,151  
Total liabilities and partners' capital
   $ 1,057,064     $ 938,715  

  See accompanying notes to the consolidated financial statements


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

   
Partnership
    
Predecessor
  
                         
   
Year Ended
December 31,
2011
    
December 22 to
December 31,
2010
    
January 1 to
December 21,
2010
    
Year Ended
December 31,
2009
  
Revenues:
                        
Oil and natural gas sales
   $ 257,903     $ 6,661     $ 244,572     $ 69,823  
Processing and other
     1,965       24       8,814       2,978  
Total revenues
     259,868       6,685       253,386       72,801  
Operating Expenses:
                                
Production expenses
     88,057       2,355       108,408       44,841  
Impairment of oil and gas properties
     -       -       -       28,338  
Depreciation, depletion and amortization
     78,354       2,130       66,482       16,993  
Accretion of asset retirement obligations
     2,702       77       3,674       3,585  
Management fees
     -       -       10,486       12,018  
Acquisition evaluation costs
     -       -       1,192       582  
Offering costs
     -       -       5,148       -  
General and administrative
     31,666       763       25,477       18,697  
Bargain purchase gain
     -       -       -       (1,200 )
Other expense
     -       -       224       -  
Total operating expenses
     200,779       5,325       221,091       123,854  
Operating income (loss)
     59,089       1,360       32,295       (51,053 )
Other income (expense):
                                
Equity in earnings of Ute Energy, LLC (See Note 15)
     -       -       3,782       2,675  
Dividends on investment in marketable equity securities
     -       -       -       233  
Gain on investment in marketable equity securities
     -       -       -       394  
Realized (losses) gains on commodity derivative contracts
     (72,053 )     (289 )     5,373       47,993  
Unrealized gains (losses) on commodity derivative contracts
     120,478       (12,068 )     8,204       (111,113 )
Gain on equity share issuance (See Note 15)
     -       -       4,064       -  
Interest expense, net
     (45,527 )     (1,136 )     (22,179 )     (3,716 )
Other income (expense)
     -       -       482       (645 )
Total other income (expense), net
     2,898       (13,493 )     (274 )     (64,179 )
Income (loss) before income taxes
     61,987       (12,133 )     32,021       (115,232 )
Income tax (expense) benefit, net
     (850 )     66       (108 )     (182 )
Net income (loss)
     61,137       (12,067 )     31,913       (115,414 )
Net income (loss) attributable to noncontrolling interest
     -       -       30,101       (107,528 )
Net income (loss) attributable to controlling interest
     61,137       (12,067 )   $ 1,812     $ (7,886 )
Net (income) loss attributable to predecessor operations
     (49,091 )     4,968                  
Distributions on Class C convertible preferred units
     (7,062 )     -                  
Net income (loss) available to other unitholders
     4,984       (7,099 )                
Less: general partner's interest in net income (loss)
     1,575       (7 )                
Limited partner's interest in net income (loss)
   $ 3,409     $ (7,092 )                
Common unitholders' interest in net income (loss)
   $ 2,730     $ (5,577 )                
Subordinated unitholders' interest in net income (loss)
   $ 679     $ (1,515 )                
Net income (loss) per limited partner unit:
                                
Common unitholders' (basic and diluted)
   $ 0.10     $ (0.21 )                
Subordinated unitholders' (basic and diluted)
   $ 0.10     $ (0.21 )                
Weighted average number of limited partner units outstanding:
                                
Common units (basic and diluted)
     28,728       26,298                  
Subordinated units (basic and diluted)
     7,146       7,146                  

See accompanying notes to the consolidated financial statements


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

                     
Limited Partners
        
   
Predecessor's
    
Class C Convertible
   
General
    
Public
    
Affiliated
    
Total
  
   
Capital
    
Preferred Unitholders
    
Partner
    
Common
    
Common
    
Subordinated
    
Partners' Capital
  
Balances - December 22, 2010
   $ 354,734     $ -     $ -     $ -     $ -     $ -     $ 354,734  
Book value of IPO Assets contributed
                                                        
by the Predecessor
     (223,736 )     -       -       -       137,051       86,685       -  
Initital public offering
     -       -       -       279,750       -       -       279,750  
Deferred tax benefit as a result of IPO
     -       -       -       134       101       64       299  
Contributions from general partner
     -       -       715       -       -       -       715  
Contributions from the Predecessor (See Note 14)
     53,034       -       -       -       -       -       53,034  
Other contributions from affiliates (See Note 14)
     482       -       -       -       113       71       666  
Recognition of unit-based awards
     -       -       -       20       -       -       20  
Distribution to the Fund
     -       -       -       -       (183,767 )     (116,233 )     (300,000 )
Net loss
     (4,968 )     -       (7 )     (3,181 )     (2,396 )     (1,515 )     (12,067 )
Balances - December 31, 2010
   $ 179,546     $ -     $ 708     $ 276,723     $ (48,898 )   $ (30,928 )   $ 377,151  
Proceeds from over-allotment
     -       -       -       41,963       -       -       41,963  
Distribution to the Fund
     -       -       -       -       (25,727 )     (16,273 )     (42,000 )
Contributions from the Predecessor (See Note 14)
     8,986       -       -       -       -       -       8,986  
Other contributions from affiliates (See Note 14)
     11,708       -       -       -       12,366       7,822       31,896  
Recognition of unit-based awards (See Note 11)
     -       -       -       1,351       -       -       1,351  
Reduction in units to cover individuals' tax withholding
     -       -       -       (215 )     -       -       (215 )
Distributions to unitholders
     -       (3,424 )     (63 )     (30,673 )     (19,854 )     (12,557 )     (66,571 )
Book value of Transferred Properties contributed by
                                                        
the Predecessor
     (249,331 )     -       -       -       -       -       (249,331 )
Fair value of Preferred Units issued to the Fund
     -       354,500       -       -       -       -       354,500  
Fair value of Preferred Units in excess of
                                                        
net assets received from the Fund
     -       -       (102 )     (49,491 )     (32,380 )     (20,481 )     (102,454 )
Amortization of discount on increasing rate distributions
     -       3,638       -       -       -       -       3,638  
Noncash distribution to preferred unitholders
     -       (3,638 )     -       -       -       -       (3,638 )
Management incentive fee earned
     -       -       (1,572 )     -       -       -       (1,572 )
Net income
     49,091       7,062       1,575       1,648       1,079       682       61,137  
Balances - December 31, 2011
   $ -     $ 358,138     $ 546     $ 241,306     $ (113,414 )   $ (71,735 )   $ 414,841  

See accompanying notes to consolidated financial statements


PREDECESSOR - QA  HOLDINGS, LP
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL
(In thousands)

   
General
Partner
    
Limited
Partners
    
Predecessor
Partners'
Capital
    
Non-controlling Interest
    
Total
Partners'
Capital
  
Balance - December 31, 2008
     59       5,898       5,957       133,978       139,935  
Contributions by partners
     14       1,427       1,441       14,550       15,991  
Distribution 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       13,312  
Contributions by partners
     141       13,921       14,062       460,802       474,864  
Distribution to partners
     (9 )     (891 )     (900 )     (29,100 )     (30,000 )
Amortization of equity awards (See Note 11)
     16       1,601       1,617       -       1,617  
Net income
     18       1,794       1,812       30,101       31,913  
Balance - December 21, 2010
   $ 151     $ 15,019     $ 15,170     $ 476,536     $ 491,706  

See accompanying notes to the consolidated financial statements


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

   
Partnership
    
Predecessor
  
   
Year Ended
December 31,
    
December 22 to
December 31,
    
January 1 to
December 21,
    
Year Ended
December 31,
  
   
2011
    
2010
    
2010
    
2009
  
Cash flows from operating activities:
                        
Net Income (loss)
   $ 61,137     $ (12,067 )   $ 31,913     $ (115,414 )
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
                                
Depreciation, depletion and amortization
     78,354       2,130       66,482       16,993  
Accretion of asset retirement obligations
     2,702       77       3,674       3,585  
Amortization of deferred financing costs
     1,520       45       2,681       627  
Recognition o f unit-based awards
     1,351       20       3,470       -  
(Gain) loss on disposal of furniture, fixtures and equipment
     -       -       (482 )     723  
General and administrative expense contributed by affiliates
     29,072       666       -       -  
Impairment of oil and gas properties
     -       -       -       28,338  
Amortization of costs of derivative contracts
     -       -       -       1,219  
Unrealized (gains) losses on commodity derivative contracts (See Note 5)
     (95,564 )     12,662       (5,598 )     108,164  
Unrealized (gains) losses on investment in marketable equity securities
     -       -       -       (5,640 )
Realized losses on investment in marketable equity securities
     -       -       -       5,246  
Deferred income tax expense
     849       (71 )     -       -  
Bargain purchase gain
     -       -       -       (1,200 )
Equity in earnings of Ute Energy, LLC
     -       -       (3,782 )     (2,675 )
Gain on equity share issuance
     -       -       (4,064 )     -  
Changes in operating assets and liabilities:
                                
Accounts receivable and other assets
     (29,029 )     (4,278 )     (39,727 )     15,052  
Accounts payable and other liabilities
     9,682       2,580       41,378       9,889  
Net cash provided by (used in) operating activities
     60,074       1,764       95,945       64,907  
Cash flows from investing activities:
                                
Additions to oil and gas properties
     (55,480 )     (318 )     (56,133 )     (31,278 )
Acquisition of oil and gas properties
     -       (77,763 )     (891,870 )     (43,300 )
Additions to furniture, equipment and other
     -       -       (1,934 )     (1,456 )
Proceeds from sale of gas processing assets
     -       -       890       -  
Proceeds from sale of other assets
     -       -       170       -  
Increase in property reclamation deposit
     -       -       -       (19 )
Investment in Ute Energy, LLC
     -       -       -       (1,925 )
Proceeds from sales of marketable equity securities
     -       -       -       6,233  
Property acquisition deposit
     -       -       (8,000 )     -  
Proceeds from sale of properties
     1,327       -       -       16,287  
Net cash used in investing activities
     (54,153 )     (78,081 )     (956,877 )     (55,458 )
Cash flows from financing activities:
                                
Proceeds from underwriters' exercise of overallotment option
     41,963       -        -        -  
Net proceeds from initial public offering (See Note 1)
     -       279,750       -       -  
Distributions to the Fund (See Note 1)
     (42,000 )     (300,000 )     -       -  
Contributions from the General Partner
     715       -        -        -  
Distrubutions to unitholders
     (46,026 )     -        -        -  
Intercompany financing from the Fund (See Note 14)
     -       387       -       -  
Contributions by partners and non-controlling interest owners
     -       -       474,864       15,991  
Distributions to partners and non-controlling interest owners
     -       -       (30,000 )     (27,019 )
Contributions from the Predecessor
     8,986       53,034       -       -  
Proceeds from bank borrowings (See Note 7)
     275,000       248,000       584,383       33,000  
Repayment of debt assumed from the Fund (See Note 7)
     (227,000 )     (200,000 )     -       -  
Repayments on bank borrowings
     -       -       (113,752 )     (35,300 )
Deferred financing costs
     (2,321 )     (2,659 )     (12,047 )     -  
Net cash provided by (used in) financing activities
     9,317       78,512       903,448       (13,328 )
Increase (decrease) in cash and cash equivalents
     15,238       2,195       42,516       (3,879 )
Cash and cash equivalents at beginning of period
     2,195       -       17,156       21,035  
Cash and cash equivalents at end of period
   $ 17,433     $ 2,195     $ 59,672     $ 17,156  

  See accompanying notes to the consolidated financial statements


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, or in any combination, 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 Partnership and the Fund are managed by Quantum Resources Management, LLC (“QRM”), a full service management company originally 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. 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, a Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) was executed by and among the Fund, the Partnership and QRE GP with net assets contributed by the Fund to the Partnership (“IPO Assets”) using carryover book value of the Fund as the transaction is a transfer of assets between entities under common control. The Contribution Agreement and other concurrent transactions included $223.7 million in net assets contributed by the Fund to the Partnership. In exchange for the net assets, the Fund received 11,297,737 common, 7,145,866 subordinated limited partner units and a $300 million cash distribution. QRE GP made a capital contribution of $0.7 million in exchange for 35,729 general partner units which was received in January 2011.

On January 3, 2011, the underwriters exercised their over-allotment option in full for 2,250,000 common units issued by the Partnership at $20.00 per unit. Net proceeds from the sale of these common units, after deducting offering costs, were approximately $42 million which, in accordance with the Contribution Agreement were distributed to the Fund as consideration for assets contributed on the Closing Date and reimbursements for pre-formation capital expenditures.

On September 12, 2011, a Purchase and Sale Agreement (“Purchase Agreement”) was executed by and among the Fund, the Partnership and OLLC with certain oil and gas properties and attributable liabilities contributed by the Fund to the Partnership (“Transferred Properties”) in exchange for 16,666,667 Class C Convertible Preferred Units (“Preferred Units”) and the assumption of $227 million in debt (the “Transaction”).

The Partnership completed the Transaction on October 3, 2011, effective on October 1, 2011 (“Effective Date”). The fair value of the Preferred Units on the Effective Date was $21.27 per unit or $354.5 million. On the Effective Date, net assets of $252.0 million were contributed by the Fund to the Partnership. The value of the Preferred Units in excess of the net assets contributed by the Fund is considered a $102.5 million distribution from the Partnership and allocated pro rata to the general partner and existing limited partners.  Net assets contributed by the Fund comprised the following:


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

 
(1)
The net assets contributed to us include the carryover book value of the Predecessor as prescribed by our accounting policy for transactions between entities under common control in Note 2 and a $2.7 million purchase price adjustment for natural gas imbalances in accordance with the Purchase Agreement.

The Preferred Units will receive a cumulative preferred quarterly distribution of $0.21 per unit equal to 4.0% annual coupon on the par value of $21.00 for the first three years following the date of issuance.  The Preferred Units have a senior liquidation preference of $21.00 per unit plus any accrued but unpaid distributions. After three years, the quarterly cash distribution will be equal to the greater of (a) $0.475 per unit or (b) the cash distribution payable on each Common Unit for such quarter. The Preferred Units are convertible, subject to certain limitations, into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment.

In connection with the issuance of the Preferred Units, on October 3, 2011, we executed Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership (the “Amendment”) to designate and create the Preferred Units and set forth the rights, preferences and privileges of such units, including the respective conversion rights held by the holders of the Preferred Units and us.

As of December 31, 2011, our ownership structure comprised a 31.8% preferred unitholder interest held by the Fund, 0.1% general partnership interest held by QRE GP, 35.2% in limited partner interests held by the Fund and 32.9% in limited partner interests held by the public unitholders.

Services Agreement

On the Closing Date, 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 Date 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

On the Closing Date, 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 14.

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, 2011 and 2010. These financial statements also include the results of our operations, cash flows and changes in partners’ capital for the year ended December 31, 2011, 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 the year ended December 31, 2009. These consolidated financial statements include our subsidiary and all of the subsidiaries of the Predecessor.

Our consolidated statement of operations and consolidated statement of cash flows reflect activity since the Closing Date. 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 2011 presentation. These reclassifications do not affect the totals for current assets, current liabilities, noncurrent assets, noncurrent liabilities, revenue, operating expenses, other income (expenses), net income or cash flows.

Because affiliates of the Fund own 100% of QRE GP and an aggregate 67.0%  limited partner interests in us, including 11,297,737 common units and all preferred and subordinated units, each acquisition of assets from the Predecessor is considered a transaction between entities under common control. As a result, the Partnership is required to revise its financial statements to include the activities of the Transferred Properties.

The Partnership’s historical financial statements previously filed with the SEC have been revised in this annual report on Form 10-K to include the results attributable to the Transferred Properties as if the Partnership owned such assets for all periods presented by the Partnership including the period from December 22, 2010 to December 31, 2010 and the year ended December 31, 2011 as the Transaction was between entities under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the Transferred Properties have been prepared from the Predecessor’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. See our accounting policy for transactions between entities under common control below.

Net income attributable to the Transferred Properties for periods prior to the Partnership’s acquisition of such assets was not available for distribution to the Partnership’s unitholders.  Therefore, this income is not allocated to the limited partners for purposes of calculating net income per common unit.

Revised Balance Sheet

Our historical balance sheet as of December 31, 2010 was impacted based on revisions from the Transferred Properties with an increase in total assets of $466.7 million comprising a $465.8 million increase in noncurrent assets and a $0.9 million increase in current assets. Total liabilities and partners’ capital was also increased by $466.7 million comprising increases of $276.8 million in noncurrent liabilities, $179.6 million in predecessor’s capital and $10.3 million in current liabilities.
 

Revised Statement of Operations

Our historical statement of operations for the period from December 22, 2010 to December 31, 2010 was impacted based on revisions from the Transferred Properties with an increase in net loss of $5.0 million comprising increases of $3.6 million in revenues, $3.2 million in operating expenses (including $1.4 million in production expenses and $1.8 million in other operating expenses), $4.6 million in unrealized losses on commodity derivatives and $0.8 million in interest expense.

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;
 
·
Fair values of assets acquired and liabilities assumed from business combinations; and
 
·
Natural gas imbalances

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

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

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. 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, 2011 and 2010, the allowance for doubtful accounts was not material to us or the Predecessor.

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, with the exception of workovers resulting in an increase in proved reserves which are capitalized.


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, 2011. 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, the Predecessor recognized impairments of oil and gas properties of $28.3 million during the quarter ended March 31, 2009. The adjusted prices used in the ceiling test as of March 31, 2009 were $48.39 per barrel for oil and $3.58 per MMbtu for natural gas.

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.

Transactions 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 net assets received using the carryover book value of the Predecessor as these are transactions between entities under common control. Our historical financial statements have been revised to include the results attributable to the assets contributed from our sponsor as if we owned such assets for all periods presented by the Partnership.

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


Long-Term Debt Assumed The carryover book value and related activity of long-term debt assumed from the Predecessor was determined by using the Effective Date amount of debt assumed per the Purchase Agreement less the debt incurred by the Predecessor for the assets acquired from Melrose Energy Company (“the Melrose Acquisition”) in order to determine the debt related to the Transferred Properties at the IPO Date. The Partnership’s revised financial statements include the beginning IPO Date balance, borrowing for the Melrose Acquisition and repayment of the assumed debt to properly reflect these debt transactions as if the Partnership owned the Transferred Properties for the periods presented by the Partnership.

Asset Retirement Obligations Received The carryover book value and related activity of asset retirement obligations received from the Predecessor was determined by using the specific obligations related to the properties listed in the Purchase Agreement. These asset retirement balances as of the Effective Date and all related previous activity dating back to the IPO Date are included in the Partnership’s revised financial statements.

Derivative Instruments Received The carryover book value and related activity of commodity and interest rate derivative instruments received from the Predecessor was determined by using the instruments listed in the Purchase Agreement. The balances of these derivative instruments as of the Effective Date and related previous unrealized gains and losses and modifications dating back to the IPO Date are included in the Partnership’s revised financial statements.

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

Oil and Gas Revenues and Expense Oil and gas revenues and expense related to Transferred Properties were determined based on operating activity for the specific properties listed in the Purchase Agreement.  All oil and gas revenues and expense activity are included in the Partnership’s revised financial statements dating back to the IPO Date.

General and Administrative Expenses The G&A expense attributable to the Transferred Properties was determined by the ratio of production for the Transferred Properties to the total Predecessor’s production.  This ratio was applied to the specific properties listed in the Purchase Agreement.  All G&A expense identified is included in the Partnership’s revised financial statements dating back to the IPO Date.

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.

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 adjust the full cost pool to the extent the actual costs differ from the recorded liability. See Note 6.


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 or expense on the statements of operations in “gains (losses) on commodity derivatives.” Realized gains and losses represent amounts related to the settlement of commodity derivatives which are aligned with the underlying production. Unrealized gains and 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. 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, 2011 or 2010.

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 2011, we evaluated our concentration of credit risk by evaluating transactions from our assets as if we owned the Transferred Properties for the entire year. This analysis of our revenue process resulted in three customers accounting for 17%, 16% and 13% of our oil, natural gas and NGL revenues.


In 2010, we evaluated our concentration of credit risk by evaluating transactions from our assets as if we owned the IPO Assets and the Transferred Properties for the entire year. This analysis of our revenue process resulted in five customers accounting for 14%, 13%, 12%, 11% and 10% of our oil, natural gas and NGL revenues.

In 2010, two customers accounted 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.

Market Risk

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

Preferred Units

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

The Preferred Units have a liquidation preference equal to $21.00 per unit outstanding and any cumulative distributions in arrears. We disclose the balance of the liquidation preference as of the end of the period in Note 10 to our consolidated financial statements.

On the Effective Date, we recorded the Preferred Units at their fair value of $21.27 per unit or $354.5 million in partners’ capital. Because the Preferred Units include stated distribution rates which increase over time, from a rate considered below market, we will amortize an incremental amount which together with the stated rate for the period results in a constant distribution rate in accordance with GAAP. We determined the present value of the incremental distributions of $46.2 million will be amortized over the period preceding the perpetual dividend rate using an effective interest rate of 8.1%. The amortization will increase the carrying value of the Preferred Units with an offsetting noncash distribution reducing the general partner’s and limited partners’ capital accounts on a pro rata basis. These distributions will be included in preferred distributions in our calculation of net income applicable to limited partners and basic and diluted net income per unit. During 2011, we recorded non-cash distributions of $3.6 million for the affect of increasing rate distributions.

There was no beneficial conversion feature as our common units were trading below the $21.27 per unit fair value of the Preferred Units as of October 3, 2011.

Revenue Recognition

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on 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 12.


General and Administrative Expenses

The Partnership shares general and administrative expenses with other affiliates who also receive management and accounting services from QRM, but the Partnership is not required to reimburse QRM for its expenses incurred on its behalf during the period covered by the Service Agreement. The administrative service fee is the only expense which is reimbursable by the Partnership to QRM.  This allocation methodology, based on relative production volumes, has been reviewed and approved by QRE GP’s board of directors, including independent directors, as a reasonable method of sharing these expenses with the Fund and provides for a reasonably accurate depiction of what our general and administrative expenses would be on a stand-alone basis without affiliations with the Fund or QRM.  After December 31, 2012, if the Services Agreement is not extended, the Partnership will be required to reimburse QRM for its share of allocable 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 fee and Allocated G&A in excess of the administrative service fee. 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 Partner’s Capital.

Upon the termination of the Services Agreement, our general and administrative expenses for each quarter will comprise Direct G&A and Allocated G&A. If the term of the service agreements is not extended, the Partnership will reimburse QRM for its direct G&A as well as its share of allocated G&A.

Allocated G&A for any quarter is calculated using the ratio of our quarterly production to the quarterly 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.

Management Incentive Fee

Under our partnership agreement, as amended, for each quarter for which we pay distributions that are equal or greater than 115% of our minimum quarterly distribution (which we refer to as our “Target Distribution”), QRE GP will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of a management incentive fee base. The calculation of the management incentive fee and the current year expense is discussed in Note 14 to the consolidated financial statements.

Income Taxes

We are treated as a partnership for federal income tax purposes. Generally, all of our federal 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 also subject to Texas Margin tax. As a result of the Fund’s IPO contribution of oil and gas properties and derivative instruments to us, we recorded a deferred tax asset of $0.3 million in 2010 based on the book to tax differences in the bases of those assets. As part of the recast financials, the Partnership recorded an additional deferred tax asset of $0.7 million in 2010 as a result Fund’s contribution of oil and gas properties and derivative instruments in 2011.


We expect to realize the benefit of the remaining asset in future periods through the generation of future taxable income and utilization of depletion deductions. For the year ended December 31, 2011 and the period of December 22, 2010 through December 31, 2010, we recognized a deferred tax expense for Texas Margin tax of $0.8 million and deferred tax benefit of $0.1 million.

Net Income (Loss) per Limited Partner Unit

Net income (loss) per limited partner unit is determined by dividing net income available to the limited partners, after deducting distributions to preferred unitholders and the general partner’s 0.1% interest in net income, by the weighted average number of limited partner units outstanding for the year ended December 31, 2011 and the period from December 22, 2010 to December 31, 2010. Basic and diluted net income (loss) per unit are generally equivalent, as all subordinated units participate in distributions. However, the Preferred Units are contingently convertible and will be included in the denominator for diluted income per unit unless they are anti-dilutive. See Note 10.

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, 2011 and 2010, we have granted awards to individuals who performed services for us. 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 11.

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 or 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 or expenses, respectively." 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 15.
 
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.
 
   
Predecessor
  
   
January 1 to
December 21,
    
Year Ended
December 31,
  
   
2010
    
2009
  
Percentage of employee's salary
     3%       6%  
Matching contributions
     0.3       0.6  


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 11 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.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). The amendments in ASU 2011-04 are the result of the FASB's and the International Accounting Standards Board's (IASB) work to develop common requirements for measuring fair value and for disclosing information about fair value measurements in accordance with GAAP in the United States and the International Financial Reporting Standards (IFRS). ASU 2011-04 explains how to measure fair value and changes the wording used to describe many of the fair value requirements in GAAP, but does not require additional fair value measurements. This guidance becomes effective for interim and annual periods beginning on or after December 15, 2011, with early adoption prohibited. This update was adopted by us on January 1, 2012 and we do not expect the adoption of this ASU to have a material impact on our financial position, results of operations or cash flows.

In December 2011, the FASB issued ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities (ASU 2011-11).  The objective of this Update is to provide enhanced disclosures that will enable the users of  its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position.  The amendment will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to the master netting arrangement.  This scope would include financial and derivative instruments that either offset in accordance with U.S. GAAP or are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with U.S. GAAP.  This amendment becomes effective for annual reporting periods beginning on or after January 1, 2013, and the interim periods within those annual periods.  We are evaluating the potential impacts this ASU will have on our disclosures.


NOTE 3 — ACQUISITIONS

Partnership Acquisitions

Effective October 1, 2011, we completed our acquisition of the Transferred Properties for an aggregate purchase price of $578.8 million. The net assets were recorded by the Partnership using carryover book value of the Fund as the acquisition is a transaction between entities under common control. Our historical financial statements were revised to include the results attributable to the Transferred Properties as if we owned the properties for all periods we have presented in our consolidated financial statements. See Note 2 for further disclosures regarding this transaction.

The Partnership’s Allocation of Melrose Acquisition by the Predecessor

A portion of the Transferred Properties includes the Predecessor’s Melrose Acquisition, on December 22, 2010 subsequent to our IPO, which qualifies as a business combination. The following table summarizes our allocated share of the consideration paid by the Predecessor for Melrose and our allocated share of the final fair value of the assets acquired and liabilities assumed as of December 22, 2010.

Allocated cost of Predecessor's acquisition
   $ 77,763  
Oil and gas properties
   $ 82,781  
Asset retirement obligations
     (5,018 )
Total identifiable net assets
   $ 77,763  

Predecessor Third Party 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 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 during 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
   $ 888,785  
Preferential rights (Not yet paid at December 31, 2010)
     4,058  
Total consideration
   $ 892,843  
Recognized amounts of identifiable assets acquired and liabilities assumed:
        
Inventory (including hydrocarbons of $1,863)
   $ 6,384  
Proved developed properties (1)
     788,829  
Proved undeveloped properties (1)
     84,000  
Unproved properties (1)
     43,000  
Suspended 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.

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
    
2009
  
   
Actual
    
Pro Forma
    
Actual
    
Pro Forma
  
Revenues
   $ 253,386     $ 343,190     $ 72,801     $ 233,778  
Net 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.

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 Paso:
      
Cash
   $ 48,700  
Recognized amounts of identifiable assets acquired and liabilities assumed:
        
Proved developed properties (1)
   $ 51,600  
Asset 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.

Summarized below are the consolidated results of operations for the years ended December 31, 2009, on an unaudited pro forma basis, as if the acquisition had occurred on January 1 of each of the periods presented. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the 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
  
   
Actual
    
Pro Forma
  
Revenues
   $ 72,801     $ 73,713  
Net Loss
   $ (115,414 )   $ (117,858 )

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.

   
2009
  
         
Pro Forma Adjustments
        
   
Actual
    
Denbury
    
Shongaloo
    
Pro Forma
  
Revenues
   $ 72,801       160,977       912     $ 234,690  
Net Loss
   $ (115,414 )     20,452       (2,444 )   $ (97,406 )
 

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). GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:

 
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 GAAP, 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, 2011 and 2010.

Partnership - As of December 31, 2011
  
Total
    
Level 1
    
Level 2
    
Level 3
  
Assets from commodity derivative instruments
   $ 103,233     $ -     $ 103,233     $ -  
Assets from interest rate derivative instruments
     20       -       20       -  
    $ 103,253     $ -     $ 103,253     $ -  
                                 
Liabilities from commodity derivative instruments
   $ 2,502     $ -     $ 2,502     $ -  
Liabilities from interest rate derivative instruments
     23,973       -       23,973       -  
    $ 26,475     $ -     $ 26,475     $ -  
Partnership - As of December 31, 2010
                                
Assets from commodity derivative instruments
   $ 36,302     $ -     $ 36,302     $ -  
Assets from interest rate derivative instruments
     -       -       -       -  
    $ 36,302     $ -     $ 36,302     $ -  
                                 
Liabilities from commodity derivative instruments
   $ 55,773     $ -     $ 55,773     $ -  
Liabilities from interest rate derivative instruments
     1,914       -       1,914       -  
    $ 57,687     $ -     $ 57,687     $ -  

 
On December 22, 2010, the Predecessor novated certain derivative instruments to us. These derivative instruments were accounted for at fair value of a $1.4 million net liability position (See Note 5). These derivative instruments are classified as Level 2 fair value measurements.

On February 28, 2011, the Predecessor novated certain interest rate derivative instruments to us. These derivative instruments were accounted for at fair value of a $2.9 million net asset position (See Note 5). These derivative instruments are classified as Level 2 fair value measurements.

In June 2011, we entered into modifications of all our existing oil fixed price swap derivative contracts by increasing the strike price of our oil contracts, effectively settling those liability positions as of June 22, 2011 with a realized loss. The modified contracts were accounted for at fair value of $40.7 million (See Note 5) and are classified as Level 2 fair value measurements.

On July 1, 2011, the Predecessor novated certain basis swap derivative instruments to us. These derivative instruments were accounted for at fair value of a $0.3 million liability position (See Note 5). These derivative instruments are classified as Level 2 fair value measurements.

On September 30, 2011, the Predecessor novated certain interest rate derivative instruments to us. These derivative instruments were accounted for at fair value of an $8.5 million  liability position (See Note 5).  The Partnership’s Statement of Financial Position has been revised to include these derivative instruments for the periods presented. These derivative instruments are classified as Level 2 fair value measurements.

On October 1, 2011, the Predecessor novated certain interest rate and commodity derivative instruments to us. These derivative instruments were accounted for at fair value of a $73.1 million net asset position (See Note 5). The Partnership’s Statement of Financial Position has been revised to include these derivative instruments for the periods presented. 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:

   
Predecessor
  
   
January 1 to
    
Year Ended
  
   
December 21,
    
December 31,
  
   
2010
    
2009
  
Balance 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 perod
   $ -     $ (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

The Partnership

Interest Rate Derivatives

In an effort to mitigate exposure to changes in market interest rates, we have entered into interest rate swaps that effectively fix the interest rate on our outstanding debt.

On February 28, 2011, the Predecessor novated to us fixed-for-floating interest rate swaps covering $225.0 million of borrowings under our revolving credit facility. The fair value of these derivative instruments was a $2.9 million net asset position comprising $6.4 million of assets from interest rate derivative contracts and $3.5 million of liabilities from interest rate derivatives.

On August 30, 2011, we entered into a fixed for floating interest rate swap agreement covering $40.0 million of borrowings under our revolving credit facility. This derivative contract fixed the LIBOR component for $40.0 million of our credit facility at 0.93% through September 2015.

On September 30, 2011, the Predecessor novated to us fixed-for-floating interest rate swaps covering an additional $120.0 million in weighted-average borrowings under our credit facility from October 1, 2011 to December 31, 2015. The fair value of these derivative instruments was an $8.5 million liability position.

On October 1, 2011, the Predecessor novated to us fixed-for-floating interest rate swaps to us covering an additional $98.4 million of weighted-average borrowings under our revolving credit facility from October 1, 2011 to December 31, 2015. The fair value of these derivative instruments was a $6.5 million liability position.

As of December 31, 2011, we had interest rate derivative contracts covering $481.5 million in weighted average principal with a fair value of a $24.0 million liability. The outstanding balance of our credit facility as of December 31, 2011 was $500.0 million. These contracts effectively fix the LIBOR component of our outstanding balance of our credit facility at 2.0% through December 2015. As of December 31, 2011, when the interest rate derivative instruments are considered, we had a weighted average effective fixed interest rate of 4.63% comprising a 2.5% applicable margin  and 2.13% fixed LIBOR rate.

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.

In May 2011 we entered into a 500 MMBtu/d natural gas collar transaction contract for the 2014 calendar year with a floor of $5.00 per MMBtu and a ceiling of $6.19 per MMBtu. On the same day we entered into a 3,000 MMBtu/d natural gas collar transaction contract for the 2015 calendar year with a floor of $5.00 per MMBtu and a ceiling of $7.50 per MMBtu.

In June 2011, we entered into modifications of all our existing oil fixed price swap contracts, effectively settling those liability positions as of June 22, 2011. As part of these modifications, we paid $40.7 million to our counter parties to increase the fixed price on the contracts from their original prices at inception to market prices as of the closing dates of the modifications. The impact of the payment resulted in the recognition of a loss on commodity derivative contracts in the consolidated statement of operations of $40.7 million and is included in our net cash used in operating activities in our consolidated statement of cash flows for the nine months ended September 30, 2011.

In July 2011, the Predecessor novated to us basis swaps with contract dates through 2014. The average hedged differential of the basis swaps range from ($0.15) to ($0.16) during the life of the contract. The fair value of these derivative instruments was $0.3 million of liability positions.

 
On July 21 and July 22, 2011, we entered into natural gas basis swaps with contract dates through 2015. The average hedged differential of the basis swaps range from ($0.11) to ($0.19) during the life of the contract.

On October 1, 2011 the Predecessor novated to us oil and gas fixed swaps, natural gas basis swaps and oil and gas collars with contract dates through 2016.  The average hedged differential of the natural gas basis swaps range from ($0.10) to ($0.20) during the lives of the contracts. The fair value of these novated derivatives instruments was a $79.7 million net asset position.

As of December 31, 2011 and 2010, we held derivative instruments to manage our exposure to changes in the price of oil and natural gas related to the oil and gas properties. As of December 31, 2011, the notional volumes of our commodity contracts were:

Commodity
  
 Index
  
2012
    
2013
    
2014
    
2015
    
2016
  
Oil positions:
                                  
Swaps
                                  
Hedged Volume (Bbls/d)
  
WTI
     4,025       4,143       3,711       2,940       270  
Average price ($/Bbls)
       $ 98.72     $ 98.23     $ 97.70     $ 97.27     $ 97.63  
Collars
                                            
Hedged Volume (Bbls/d)
  
WTI
                     425       1,025          
Average floor price ($/Bbls)
                       $ 90.00     $ 90.00          
Average ceiling price ($/Bbls)
                       $ 106.50     $ 110.00          
                                             
Natural gas positions:
                                            
Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     30,392       29,674       25,907       6,100          
Average price ($/MMBtu)
       $ 5.86     $ 6.07     $ 6.23     $ 5.52          
Basis Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     20,723       18,466       17,066       14,400          
Average price ($/MMBtu)
       $ (0.15 )   $ (0.17 )   $ (0.19 )   $ (0.19 )        
Collars
                                            
Hedged Volume (MMBtu/d)
  
Henry Hub
     2,623       2,466       4,966       18,000          
Average floor price ($/MMBtu)
       $ 6.50     $ 6.50     $ 5.74     $ 5.00          
Average ceiling price ($/MMBtu)
       $ 8.60     $ 8.65     $ 7.51     $ 7.48          
 
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 made payments to the contract counterparties when the variable interest rate of the one-month LIBOR fell below the fixed rate of 2.74% during the period from June 2010 to December 2010. In addition, the Predecessor made payments to the contract counterparties when the one-month LIBOR fell below 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.

As of December 31, 2009, the notional volumes of the Predecessor’s commodity hedges were:

Commodity
  
 Index
  
2010
    
2011
    
2012
    
2013
    
2014
  
Oil positions:
                                  
Swaps
                                  
Hedged Volume (Bbls/d)
  
WTI
     3,640       2,961       2,611       2,455       766  
Average price ($/Bbls)
       $ 71.20     $ 68.25     $ 67.54     $ 66.80     $ 67.93  
Collars
                                            
Hedged Volume (Bbls/d)
  
WTI
     -       700       -       70       70  
Average floor price ($/Bbls)
       $ -     $ 70.00     $ -     $ 60.00     $ 60.00  
Average ceiling price ($/Bbls)
       $ -     $ 110.00     $ -     $ 77.93     $ 77.93  
                                             
Natural gas positions:
                                            
Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     11,272       10,079       4,738       4,387       2,632  
Average price ($/MMBtu)
       $ 7.53     $ 7.32     $ 7.04     $ 6.82     $ 6.53  
Basis Swaps
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     -       2,967       2,630       2,473       2,473  
Average price ($/MMBtu)
       $ -     $ (0.16 )   $ (0.16 )   $ (0.15 )   $ (0.15 )
Collars
                                            
Hedged Volume (MMBtu/d)
  
NYMEX
     1,611       -       -       -       -  
Average floor price ($/MMBtu)
       $ 7.00     $ -     $ -     $ -     $ -  
Average ceiling price ($/MMBtu)
       $ 8.90     $ -     $ -     $ -     $ -  
Collars
                                            
Hedged Volume (MMBtu/d)
  
Henry Hub
     -       -       2,518       2,518       2,518  
Average floor price ($/MMBtu)
       $ -     $ -     $ 6.50     $ 6.50     $ 6.50  
Average ceiling price ($/MMBtu)
       $ -     $ -     $ 8.70     $ 8.70     $ 8.70  


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
  
    2011     2010  
   
Asset
    
Liability
    
Asset
    
Liability
  
   
Derivatives
    
Derivatives
    
Derivatives
    
Derivatives
  
                           
Commodity contracts
   $ 103,233     $ 2,502     $ 36,302     $ 55,773  
Interest rate contracts
     20       23,973       -       1,914  
    $ 103,253     $ 26,475     $ 36,302     $ 57,687  
                                 
Commodity
                                
Current
   $ 32,683     $ 1,284     $ 9,887     $ 9,727  
Noncurrent
     70,550       1,218       26,415       46,046  
    $ 103,233     $ 2,502     $ 36,302     $ 55,773  
Interest
                                
Current
   $ -     $ 8,285     $ -     $ 1,159  
Noncurrent
     20     $ 15,688       -       755  
    $ 20     $ 23,973     $ -     $ 1,914  
                                 
Total Derivatives
                                
Current
   $ 32,683     $ 9,569     $ 9,887     $ 10,886  
Noncurrent
     70,570       16,906       26,415       46,801  
    $ 103,253     $ 26,475     $ 36,302     $ 57,687  


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

   
Partnership
    
Predecessor
  
   
Year Ended
    
December 22 to
    
January 1 to
    
Year Ended
December 31,
  
   
December 31,
    
December 31,
    
December 21,
  
   
2011
    
2010
    
2010
    
2009
  
Realized gains (losses):
                        
Commodity contracts (1)
   $ (72,053 )   $ (289 )   $ 5,373     $ 47,993  
Interest rate swaps
     (4,512 )     -       (4,808 )     (3,299 )
Total
   $ (76,565 )   $ (289 )   $ 565     $ 44,694  
                                 
Unrealized gains (losses):
                                
Commodity contracts (1)
   $ 120,478     $ (12,068 )   $ 8,204     $ (111,113 )
Interest rate swaps
     (24,914 )     (594 )     (2,606 )     2,949  
Total
   $ 95,564     $ (12,662 )   $ 5,598     $ (108,164 )
                                 
Total gains (losses):
                                
Commodity contracts
   $ 48,425     $ (12,357 )   $ 13,577     $ (63,120 )
Interest rate swaps (2)
     (29,426 )     (595 )     (7,414 )     (350 )
Total
   $ 18,999     $ (12,952 )   $ 6,163     $ (63,470 )
 
 
(1)
Gains (losses) on commodity derivative contracts are located in other income (expense) in the consolidated statement of operations.
 
(2)
Losses on interest rate derivative contracts are recorded as part of interest expense and are located in other income (expense) in the consolidated statement of operations.

See Note 2 and Note 4 for additional disclosures related to derivative instruments.

NOTE 6 — ASSET RETIREMENT OBLIGATIONS

The total undiscounted amount of future cash flows to settle our asset retirement obligations is estimated to be $222.2 million and $162.0 million at December 31, 2011 and 2010. We recorded a discounted total of approximately $43.4 million for future asset retirement obligations in connection with the conveyance of net assets from the Fund. 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 61 years. Estimated cash flows have been discounted at our credit adjusted risk free rate of 5.59% and adjusted for inflation using a rate of 2.25%.
 
Changes in the asset retirement obligations are presented in the following table:

   
Partnership
    
Predecessor
  
         
December 22
    
January 1
  
   
Year Ended
    
to
    
to
  
   
December 31,
    
December 31,
    
December 21,
  
   
2011
    
2010
    
2010
  
Beginning of period
   $ 43,414     $ 38,319     $ 35,244  
Assumed in acquisitions
     -       5,018       24,849  
Revisions to previous estimates(1)
     19,456       -       1,494  
Liabilities incurred
     377       -       -  
Liabilities settled
     (248 )     -       (747 )
Accretion expense
     2,702       77       3,674  
End of period
   $ 65,701     $ 43,414     $ 64,514  
Less: Current portion of asset retirement obligations
     (348 )     (4,166 )     (4,187 )
Asset retirement obligations -   non-current
   $ 65,353     $ 39,248     $ 60,327  
 
 
(1)
In 2011 we recorded upward revisions to previous estimates for our asset retirement obligations due to increases in future plugging and abandonment costs and changes to the remaining lives of our wells.
 
In 2011 we recorded upward revisions to previous estimates for our asset retirement obligations due to increases in future plugging and abandonment costs and changes to the remaining lives of our wells.

NOTE 7 — LONG-TERM DEBT

Consolidated debt obligations consisted of the following as of the dates indicated:

   
December 31,
  
   
2011
    
2010
  
Senior secured revolving credit facility, variable rate, due December, 2015 (1)
   $ 500,000     $ 225,000  
Long-term debt allocated from the Predecessor (2)
     -       227,000  
    $ 500,000     $ 452,000  

 
(1)
As of December 31, 2011, we had availability under this facility of $129.6 million after giving effect to outstanding borrowings of $500 million and $0.4 million of outstanding letters of credit. 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, 2010, the portion of the Predecessor’s credit facility collateralized by the Transferred Properties was $227 million.

The Partnership

On December 22, 2010, in connection with the IPO, the Partnership entered into a Credit Agreement along with QRE GP, OLLC as Borrower, and a syndicate of banks (the “Credit Agreement”)
 
The Credit Agreement provides for a five-year, $750.0 million revolving credit facility maturing on December 22, 2015, with a borrowing base of approximately $630.0 million as of December 31, 2011. The borrowing base will be subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year 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 at such time, as adjusted for the impact of our commodity derivative contracts.  On July 13, 2011, we received an interim borrowing base redetermination under our Credit Agreement which increased the borrowing base to $330.0 million. We requested and received this interim redetermination as a result of improvements in our net derivative position due to the buyup of our existing oil fixed price swap contracts in June 2011. On October 3, 2011, we amended our revolving credit facility to, among other things, increase the borrowing base by $300.0 million, resulting in a total borrowing base of $630 million.  This amendment also modified certain provisions and covenants of to allow for the successful consummation of the transactions related to the Purchase Agreement, the issuance of the Preferred Units and the related entry into the amendment to our partnership agreement (See Note 14). The administrative agent of our Credit Agreement has accepted this amendment in lieu of our semiannual redetermination required on November 1, 2011. 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.
 
As of December 31, 2011 and 2010, we had $500.0 million and $225.0 million of borrowings outstanding and $129.6 million of borrowing availability as of December 31, 2011.  In June 2011, we borrowed $41 million in connection with the modification of certain commodity derivative contracts and in October 2011, we borrowed an additional $234 million to repay the $227 million of debt assumed in connection with the Transferred Properties.
 
The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable debt obligation during the year ended December 31, 2011:

   
Range of
    
Weighted Average
  
   
Interest Rates
    
Interest Rate
  
Senior secured revolving credit facility
   2.93% - 4.69%     4.43%  

The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of 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 to provide audited financial statements within 90 days of year end and 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, 2011, we were in compliance with all of the Credit Agreement covenants.

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 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.

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 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 the fiscal year and 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 commitment 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, 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 8 — COMMITMENTS AND CONTINGENCIES

Services Agreement

The Partnership

We have entered into a Services Agreement with QRM as described in Note 14, 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, 2011.

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 was $0.8 million and $3.0 million.

Legal Proceedings

The Partnership
 
In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount.  We currently have no legal proceedings with a probable adverse outcome. Therefore, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
 
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 was involved in various suits and claims arising in the normal course of business. The Predecessor related entities owning working interests 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 believed it had 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 believed there is no evidence to support a material liability.

In management’s opinion, the ultimate outcome of these items would 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 were recorded as of December 21, 2010.

NOTE 9 — PARTNERS’ CAPITAL

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, 2011, our outstanding partnership interests consisted of 16,666,667 Class C Preferred Units, 28,590,016 outstanding common units and 7,145,866 outstanding subordinated units, representing a 99.9% limited partnership interest in us, and a 0.1% general partnership interest represented by 35,729 general partner units.

As of December 31, 2010, our outstanding partnership interests 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% general partnership interest comprising 35,729 general partner units.


The table below details the outstanding units for the period from December 22, 2010 to December 31, 2010 and the year ended December 31, 2011.

               
Limited Partners
  
         
General
          
Affiliated
  
   
Preferred Units
    
Partner
    
Public Common
    
Common
    
Subordinated
  
Balance - December 22, 2010
     -       -       -       -       -  
Units issued to the Predecessor in exchange for IPO Assets
     -       -       -       11,297,737       7,145,866  
Initial public offering
     -       -       15,000,000       -       -  
Units issued to the general partner
     -       35,729       -       -       -  
Balance - December 31, 2010
     -       35,729       15,000,000       11,297,737       7,145,866  
Underwriters' exercise of over-allotment
     -       -       2,250,000       -       -  
Units awarded under our Long Term Incentive
                                        
Performance Plan
     -       -       52,798       -       -  
Reduction in units to cover individuals'tax witholdings
     -       -       (10,519 )     -       -  
Preferred Units issued to Predecessor in exchange for Transferred Properties
     16,666,667       -       -       -       -  
Balance - December 31, 2011
     16,666,667       35,729       17,292,279       11,297,737       7,145,866  

Class C Preferred Units

On October 3, 2011 (the “Issue Date”) we amended our First Amended and Restated Agreement of Limited Partnership to designate and create the Preferred Units and set forth rights, preferences and privileges of such units including distribution rights held by the Preferred Units and us.  For the period beginning on the Issue Date and ending on the December 31, 2014, we will distribute $0.21 per unit on a quarterly basis.  Beginning on January 1, 2015, distributions on Preferred Units will be the greater of $0.475 per unit or the distribution payable on Common Units with respect to such quarter. The Preferred Units are only redeemable for cash in a complete liquidation. The Preferred Units are convertible into common units under specific circumstances at the option of either the holder or the Partnership. The Preferred Units have the same voting rights as common units. As of December 31, 2011 we have accrued a fourth quarter distributions payable of $3.4 million to Preferred Unit holders to be paid on February 10, 2012.
 
Holders may convert the Preferred Units to common units on a one-to-one basis prior to October 3, 2013, 30 consecutive trading days during which the volume-weighted average price for our common units equals or exceeds $27.30 per common unit. In addition, holders may convert the Preferred Units to common units on a one-to-one basis anytime on or after October 3, 2013.

If the holders have not converted the Preferred Units to common units by October 3, 2014, we may force conversion on a one-to-one basis, provided that conversion is in the 30 calendar days following 30 consecutive trading days during which the volume-weighted average price for common units equals or exceeds (1) $30.03, provided that (a) an effective shelf registration statement covering resales for the converted units is in place or (2) $27.30, provided that (a) above is satisfied and (b) there exists an arrangement for one or more investment banks to underwrite the converted unit sale following conversion (with proceeds equal to not less than $27.30 less (i) a standard underwriting discount and (ii) a customary discount not to exceed 5% of $27.30).

We may force conversion on a one-to-one basis after October 3, 2016, provided the conversion is in the 30 calendar days following 30 consecutive trading days during which the volume-weighted average price for common units equals or exceeds $27.30 and an effective shelf registration statement covering resales for the converted units is in place.
 
Registration Rights Agreement
 
In connection with the acquisition of the Transferred Properties, on October 3, 2011, we entered into a Registration Rights Agreement with the Fund (the “Registration Rights Agreement”), which granted certain registration rights to the Fund, including rights to (a) cause the Partnership to file with the SEC up to five shelf registration statements under the Securities Act for the resales of the common units to be issued upon conversion of the Preferred Units, and in certain circumstances, the resales of the Preferred Units, and (b) participate in future underwritten public offerings of the our common units.

The Fund may exercise its right to request that a shelf registration statement be filed any time after June 1, 2012. In addition, we agreed to use commercially reasonable efforts (a) to prepare and file a shelf registration statement within 60 days of receiving a request from the Fund and (b) to cause the shelf registration statement to be declared effective by the SEC no later than 180 days after its filing. The Registration Rights Agreement contains customary representations, warranties and covenants, and customary provisions regarding rights of indemnification between the parties with respect to certain applicable securities law liabilities.
 
These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.
 
Common Units

The common units have limited voting rights as set forth in our partnership agreement.

Pursuant to our partnership agreement, if at any time QRE GP and its affiliates own more than 80% of the outstanding common units, QRE GP has the right, but not the obligation, to purchase all of the remaining common 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 to the preferred unitholders to the extent distributions are made to them during the period with the remaining income being 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.

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, as amended, requires that within 45 days after the end of each quarter, we distribute all of our available cash to preferred unitholders, in arrears, and common unitholders of record on the applicable record date, as determined by QRE GP.


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

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

 
(i)
provide for the proper conduct of our business,

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

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

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

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

During Subordination Period.   Our partnership agreement, as amended, requires that we make distributions of available cash from operating surplus for any quarter in the following manner during the subordination period:

 
·
first, to QRE GP and common unitholders in accordance with their percentage interest until there has been distributed in respect of each Common Unit then outstanding an amount equal to the minimum quarterly distribution of $0.4125 per unit per whole quarter (or $1.65 per year);

 
·
second, to QRE GP and common unitholders in accordance with their percentage interest until there has been distributed in respect of each Common Unit then outstanding an amount equal to the cumulative common unit arrearage existing with respect to such Quarter;

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

 
·
thereafter, to QRE GP and all unitholders (other than preferred unitholders), pro rata;

After Subordination Period.   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 (other than preferred unitholders), pro rata


The following table shows the amount of cash distributions we have paid to date:

   
For the
  
Distributions to
   
Distributions per
    
General
    
Public
    
Affiliated
    
Total Distributions to
   
Distributions
  
 Date Paid
  
 period ended
  
Preferred Unitholders
    
Preferred Unit (1)
    
Partner
    
Common
    
Common
    
Subordinated
    
Other Unitholders (2) (3)
    
per other units (2) (3)
  
(In thousands, except per unit amounts)
  
February 11, 2011
  
December 31, 2010
   $ -     $ -     $ 2     $ 779     $ 506     $ 320     $ 1,607     $ 0.0448  
May 13, 2011
  
March 31, 2011
     -       -       15       7,186       4,660       2,948       14,809       0.4125  
August 12, 2011
  
June 30, 2011
     -       -       15       7,184       4,660       2,948       14,807       0.4125  
November 11, 2011
  
September 30, 2011
     -       -       15       7,180       4,660       2,948       14,803       0.4125  
February 10, 2012
  
December 31, 2011
     3,424       0.2054       16       8,344       5,368       3,393       17,121       0.4750  
 
 
(1)
Preferred Units were prorated a quarterly distribution for the portion of the fourth quarter beginning on October 3, 2011 through December 31, 2011 in accordance with the Partnership Agreement.
 
(2)
The first quarter 2011 minimum quarterly distribution was prorated for the 10 day period from December 22, 2010 to December 31, 2010 in accordance with the Partnership Agreement.
 
(3)
An increase in the quarterly distribution to $0.475 was declared by the board of directors on October 3, 2011 and accrued in the fourth quarter 2011.

NOTE 10 — NET INCOME (LOSS) PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income (loss) per limited partner unit for the year ended December 31, 2011 and the period from December 22, 2010 through December 31, 2010:

         
December 22 to
  
   
2011
    
December 31, 2010
  
Net income (loss)
   $ 61,137     $ (12,067 )
Net (income) loss attributable to predecessor operations
     (49,091 )     4,968  
Distribution on Class C convertible preferred units
     (7,062 )     -  
Net income (loss) available to other unitholders
     4,984       (7,099 )
Less: general partner's interest in net income (loss)
     1,575       (7 )
Limited partner's interest in net income (loss)
   $ 3,409     $ (7,092 )
Common unitholders' interest in net income (loss)
   $ 2,730     $ (5,577 )
Subordinated unitholders' interest in net income (loss)
   $ 679     $ (1,515 )
Net income (loss) per limited partner unit:
                
Common unitholders' (basic and diluted)
   $ 0.10     $ (0.21 )
Subordinated unitholders' (basic and diluted)
   $ 0.10     $ (0.21 )
Weighted average number of limited partner units outstanding(1):
                
Common units (basic and diluted)
     28,728       26,298  
Subordinated units (basic and diluted)
     7,146       7,146  

 
(1)
In 2011, we had weighted average preferred units outstanding of 4,109,589, which are contingently convertible.  These units could potentially dilute earnings per unit in the future and have not been included in the 2011 earnings per unit calculation as they were antidilutive for the period.

Net income per limited partner unit is determined by dividing the limited partners’ interest in net income, and net income available to the common unitholders, by the weighted average number of limited partner units outstanding during the year ended December 31, 2011 and the period from December 22, 2010 to December 31, 2010.

We had 28,590,016 common units and 7,145,866 subordinated units outstanding as of December 31, 2011 and we had 26,297,737 common units and 7,145,866 subordinated units outstanding as of December 31, 2010.

NOTE 11 — 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 restricted unit awards to individuals who performed services for us in support of the completion of our IPO. The fair value of the common unit award granted was calculated based on the closing price of our common units on the grant date, $20.03 per common unit, which we expect will be recognized in expense over vesting periods of up to five years.

We recognize the expense related to unvested restricted units using a straight-line amortization method over the entire award even though tranches vest annually over a three or five year period.  For the year ended December 31, 2011 and the period from December 22, 2010 to December 31, 2010, we recognized compensation expense related to these awards of $1.4 million and less than $0.1 million. As of December 31, 2011, we had 271,364 restricted unit awards outstanding and 30,731 vested common units with remaining unamortized costs which had a combined $4.8 million unamortized grant date fair value which we expect will be recognized in expense over a weighted average period of three years.

On January 4, 2011, we granted common unit awards of 3,750 units to each of our two independent directors. These units vested immediately upon grant. 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 March 9, 2011, we granted restricted common unit awards of 8,985 units each 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, and we expect to recognize this in expense over the three year vesting period.

On July 1, 2011, we granted a common unit award of 1,817 units to a newly elected independent director. These units vested immediately upon grant. The fair value of the common unit award granted was calculated based on the closing price of our common units on the grant date, $20.62 per common unit.

On November 1, 2011, we granted a restricted common unit award of 170,752 units to employees of QRM. The fair value of the common unit awards granted was calculated based on the closing price of our common units on the grant date, $20.28 per common unit and we expect to recognize this in expense over the three year vesting period. The common units awarded pursuant to this grant were issued to 96 total employees, of which only four were Section 16 officers, three of which Section 16 officers had previously not participated in the long-term incentive plan.


The following table summarizes the Partnership’s unit-based awards for the year ended December 31, 2011 and from December 22, 2010 through December 31, 2010 (in thousands, except per unit amounts):

         
Weighted
  
   
Number of
    
Average
  
   
Unvested
    
Grant-Date
  
   
Restricted
    
Fair Value
  
   
Units
    
per unit
  
Unvested units, December 22, 2010
     -     $ -  
Granted
     148     $ 20.03  
Forfeited
     -     $ -  
Vested
     -     $ -  
Unvested units, December 31, 2010
     148     $ 20.03  
Granted
     215     $ 20.51  
Forfeited
     (39 )   $ 20.75  
Vested
     (53 )   $ 20.31  
Unvested units, December 31, 2011
     271     $ 20.26  

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 21, 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 the awards 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.


         
Weighted
  
         
Average
  
   
% of
    
Grant Date
  
   
Interest
    
Fair Value
  
Activity related to the GP Funded Interests is as follows:
  
Granted
    
Per 1%
  
Nonvested GP Funded Interests as of December 31, 2008
     0.00 %   $ -  
Granted
     72.82 %     57,512  
Forfeited
     0.00 %        
Nonvested GP Funded Interests as of December 31, 2009
     72.82 %   $ 57,512  
Granted
     22.05 %     88,206  
Forfeited
     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:
            
         
Weighted
  
         
Average
  
   
% of
    
Grant Date
  
   
Interest
    
Fair Value
  
   
Granted
    
Per 1%
  
Nonvested GP Promote Interests as of December 31, 2008
     0.00 %   $ -  
Granted
     78.83 %     71,534  
Forfeited
     0.00 %        
Nonvested GP Promote Interests as of December 31, 2009
     78.83 %   $ 71,534  
Granted
     17.45 %     97,544  
Forfeited
     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 %

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:
            
         
Weighted
  
         
Average
  
   
% of
    
Grant Date
  
   
Interest
    
Fair Value
  
   
Granted
    
Per 1%
  
Nonvested Purchase/Carry Interests as of December 31, 2008
     0.00 %   $ -  
Granted
     100.00 %     13,278  
Forfeited
     0.00 %        
Nonvested Puchase/Carry Interests as of December 31, 2009
     100.00 %   $ 13,278  
Granted
     0.00 %     -  
Forfeited
     0.00 %        
Nonvested Purchase/Carry Interests as of December 21, 2010
     100.00 %   $ 13,278  

Nonvested Purchase/Carry Interests as of December 31, 2008
     0.00 %
Granted
     100.00 %
Vested
     0.00 %
Forfeited
     0.00 %
Nonvested Puchase/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 %

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 12 – ACCRUED AND OTHER LIABILITIES

As of December 31, 2011 and December 31, 2010 we had the following accrued and other liabilities:

   
December 31, 2011
    
December 31, 2010
  
Distributions payable (1)
   $ 20,545     $ -  
Accrued capital spending
     9,591       39  
Accrued lease operating expenses
     8,412       712  
Accrued production taxes
     4,460       184  
Gas imbalance liability (2)
     4,010       5,456  
Other
     3,009       1,630  
    $ 50,027     $ 8,021  

 
(1)
Includes distributions payable to our general partner and limited partners of $17.1 million and preferred distributions payable of $3.4 million.

 
(2)
We account for our natural gas imbalances under the sales method. We had overproduced liabilities of $4.0 million and $5.4 million included in accrued liabilities on our consolidated balance sheet as of December 31, 2011 and December 31, 2010 for overproduced positions which were beyond ultimate recoverability of remaining natural gas reserves. As of December 31, 2011, our gross underproduced natural gas position was approximately $1.1 million (1.6 MMcf) and our gross overproduced natural gas position was approximately $4.0 million (2.3 MMcf). These gross positions were valued at $3.01 per Mcf for underproduced natural gas positions and $2.96 per Mcf for overproduced natural gas positions without regard to 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 $5.4 million (1,854 MMcf). These gross positions were valued at $4.00 per Mcf without regard to remaining natural gas reserves.
 
NOTE 13 — SIGNIFICANT CUSTOMERS

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

   
Partnership
      
Predecessor
  
   
2011(1)
    
2010(1)
      
2010
    
2009
  
ConocoPhillips
     16%       13%          (2)       (2)  
Plains Marketing LP
     13%       14%          (2)       10%  
Shell Trading US Company
     (2)       12%         45%       24%  
Sunoco Inc R&M
     (2)       10%         10%       12%  
ExxonMobil Corporation
     17%       11%         (2)        (2)  

 
(1)
In 2011 and 2010 these percentages are reflective as if the Partnership owned all acquired properties 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.

NOTE 14 — RELATED PARTY TRANSACTIONS

Ownership in QRE GP by the Management of the Fund and its Affiliates
 
As of December 31, 2011, affiliates of the Fund owned 100% of QRE GP, an aggregate 67% limited partner interest in us represented by 11,297,737 of our common units and all of our preferred and subordinated units. In addition, QRE GP owned a 0.1% general partner interest in us, represented by 35,729 general partner units.
 
As of December 31, 2010, affiliates of the Fund owned 100% of QRE GP, an aggregate 55.1% limited partner interest in us represented by 11,297,737 of our common units and all of our subordinated units. 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.

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.

For the year ended December 31, 2011 and for the period from December 22, 2010 to December 31, 2010, the Fund charged us $2.5 million and $0.1 million in administrative services fee in accordance with the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM.

 In connection with the management of our business, QRM provides services for invoicing and collection of our revenues as well as processing of payments to our vendors. Periodically QRM remits cash to us for the net working capital received on our behalf. Changes in the affiliate (payable)/receivable balances during the year ended December 31, 2011 and the period from December 22, 2010 to December 31, 2010 are included below:

Beginning balance as of December 22, 2010
   $ -  
Ad valorem taxes paid by the Fund on our behalf
     (22 )
Interest paid by the Fund on our behalf
     (263 )
Debt issue costs paid by the Fund on our behalf
     (102 )
Intercompany financing from the Fund
     (387 )
Administrative services fee due to the Fund
     (55 )
Net affiliate payable as of December 31, 2010
     (442 )
Revenues and other increases (1) (2)
     130,946  
Expenditures
     (70,367 )
Settlements from the Fund
     (56,403 )
Net affiliate receivable as of December 31, 2011
   $ 3,734  
 
 
(1)
Includes $1.6 million in overhead producing credits and $1.3 million of proceeds from the sale of oil and gas leases received by the Fund on our behalf.
 
(2)
Includes $2.7 million in purchase price adjustments receivable from the Fund related to natural gas imbalances included with the Transferred Properties on October 3, 2011.


Other Contributions to Partners’ Capital

Other contributions to partners’ capital for the year ended December 31, 2011 include the following items:

         
December 22 to
  
   
2011
    
December 31, 2010
  
Noncash general and administrative expense contributed by the Fund(1)
   $ 17,364     $ 184  
Noncash general and administrative expense contributed by the Predecessor(2)
     11,708       482  
Fair value of interest rate derivatives novated to us from the Fund(3)
     2,600       -  
Prepaid insurance incurred by the Fund on our behalf(4)
     224       -  
Total other contributions from affiliates
   $ 31,896     $ 666  

 
(1)
Represents our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us for the IPO Assets during 2011 and for the Transferred Properties effective October 1, 2011 through December 31, 2011.
 
(2)
Represents our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us for the Transferred Properties from January 1 to December 31, 2011.
 
(3)
On February 28, 2011, the Fund novated to us fixed-for-floating interest rate swaps covering $225.0 million of borrowings under our revolving credit facility. The Fund also novated to us on July 1, 2011 natural gas basis swaps with contract dates until 2015. The fair value of these derivative instruments was a net asset position.
 
(4)
QRM also incurred prepaid insurance on our behalf, but not reimbursable by us.

Cash Contributions from the Predecessor

The following table presents cash received and payments made by the Predecessor on our behalf as well as allocated cost from the Predecesser's aquisition of the Melrose Properties related to the Transferred Properties for the following periods prior to our acquisition of the net assets on October 3, 2011:

         
December 22
  
   
Year ended
    
to
  
   
2011
    
December 31, 2010
  
 Cash receipts
   $ (103,862 )   $ (3,670 )
 Borrowings under Predecessor's credit facility
     -       (23,000 )
 Production expdenditures paid
     36,719       1,416  
 Derivative buyup payment
     42,653       -  
 Interest paid
     5,598       207  
 Acquisition of Melrose Properties
     -       77,763  
 Capital expenditures paid
     27,878       318  
 Cash contributions from the Predecessor
   $ 8,986     $ 53,034  

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 $193.2 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.

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 year ended December 31, 2011 the management incentive fee earned by our QRE GP was $1.6 million. For the period from December 22, 2010 to December 31, 2010, no management incentive fees were earned by or paid to our QRE GP.

Purchase and Sale Agreement

On October 3, 2011 (effective October 1, 2011) we completed an acquisition of certain oil and gas properties located in the Permian Basin, Ark-La-Tex and Mid-Continent areas from the Fund for an aggregate purchase price of $578.8 million, pursuant to a Purchase and Sale Agreement (the “Purchase Agreement”) dated September 12, 2011. In exchange for the assets, we assumed $227.0 million in debt from the Fund which was repaid at closing and issued to the Fund 16,666,667 unregistered Preferred Units. See Note 1 for further discussion.

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, 2011 and 2010, 271,364 and 148,150 restricted unit awards with a fair value of $4.8 million and $2.8 million were granted under the Plan. For additional discussion regarding the Plan see Note 11.

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, 2011 and 2010, QRE GP and its affiliates held 11,297,737 common units, all of the subordinated units and 35,729 QRE GP units. We distributed less than $0.1 million to QRE GP during the year ended December 31, 2011. No cash distributions were made from December 22, 2010 through December 31, 2010. The Partnership made a cash distribution on February 10, 2012 as discussed in Note 9.


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.

NOTE 15 – 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.

There were no impairments during the period from January 1, 2010 to December 21, 2010 or during 2009.

During 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 $4,064,000The 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 25to 23.8%.

The Predecessor’s equity in earnings of Ute was $3.8 million and $2.7 millionfor the period of January 1, 2010 through December 21, 2010, and for the year ended December 31, 2009. 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 to
December 21,
2010
    
2009
  
Revenues
   $ 37,818     $ 10,025  
Operating expenses
     (27,071 )     (14,059 )
Operating profit (loss)
     10,747       (4,034 )
Interest expense
     (2,192 )     (2,275 )
Other income/(expense)
     7,163       4,999  
Net income (loss)
   $ 15,718     $ (1,310 )

   
December 31,
  
   
2009
  
Current assets
   $ 2,288  
Net oil and gas properties
     34,417  
Equity method investments
     94,248  
Other assets
     1,978  
Total assets
   $ 132,931  
         
Current liabilities
   $ 5,538  
Long-term liabilities
     52,010  
Members’ equity
     75,383  
Total liabilities and members’ equity
   $ 132,931  
 

NOTE 16 – SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information was as follows for the periods indicated:

   
Partnership
    
Predecessor
  
         
December 22
    
January 1
        
   
Year Ended
    
to
    
to
    
Year Ended
  
   
December 31,
    
December 31,
    
December 21,
    
December 31,
  
   
2011
    
2010
    
2010
    
2009
  
Supplemental Cash Flow Information
                        
Cash paid during the period for interest
     18,082     $ 471     $ 11,244     $ 2,480  
Cash paid for state income tax
     -       -       108       182  
Non-cash Investing and Financing Activities
                                
Net book value of assets contributed by the Fund
     (249,331 )   $ (223,736 )   $ -     $ -  
Change in accrued capital expenditures
     9,551       39       6,906       (11,206 )
Insurance premium financed
     -       1,308       2,075       1,695  
Contributions receivable from QRE GP
     -       715       -       -  
Interest rate swaps novated from the Fund
     2,600       -       -       -  
Accrued distributions
     (20,545 )     -       -       -  
Management incentive fee incurred
     (1,572 )     -       -       -  
Amortization of increasing rate distributions (1)
     3,638       -       -       -  

 
(1)
Amortization of increasing rate distributions is offset in the preferred unitholders’ capital account by a non-cash distribution.

NOTE 17 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after December 31, 2011, up until the issuance of the financial statements.

On October 4, 2011, the board of directors of QRE GP declared a quarterly distribution of $0.475 per unit, or $1.90 on an annualized basis, for the fourth quarter of 2011 for all outstanding units. The Partnership also accrued distributions of $0.21 per unit for the Preferred Units’ quarterly distribution in the fourth quarter of 2011. These distributions were paid on February 10, 2012 to unitholders of record at the close of business on January 30, 2012. The aggregate amount of the distribution was $20.5 million.

During January and March 2012, we entered into additional crude oil hedges for the years 2012 through 2016.  These contracts were entered into with the same counterparties as our existing derivatives. The table below details the newly executed contracts.

Commodity
  
 Index
  
Feb 1 - Dec 31,
2012
    
2013
    
2014
    
2015
    
2016
  
Oil positions:
                                  
Swaps
                                  
Hedged Volume (Bbls/d)
  
WTI
     1,000       1,300       800       -       -  
Average price ($/Bbls)
       $ 99.36       99.12     $ 95.41       -       -  
Collars
                                            
Hedged Volume (Bbls/d)
         -       -       -       -       1,500  
Average floor price ($/Bbls)
         -       -       -       -     $ 80.00  
Average ceiling price ($/Bbls)
         -       -       -       -     $ 102.00  


SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Capitalized Costs

The following table sets forth the capitalized costs related to our oil and natural gas producing activities as of the dates indicated:

   
Partnership
  
   
December 31,
 2011
    
December 31,
 2010
  
Proved oil and natural gas properties
   $ 975,182     $ 892,649  
Unproved oil and natural gas properties
     -       -  
      975,182       892,649  
Accumulated depreciation, depletion and amortization
     (80,469 )     (2,130 )
Net capitalized costs
   $ 894,713     $ 890,519  

Pursuant to the FASB’s authoritative guidance on asset retirement obligations, net capitalized costs include asset retirement costs of $59.9 million and $40.0 million as of December 31, 2011 and 2010.

Costs Incurred

Our oil and natural gas activities are conducted in the United States. The following table summarizes the costs incurred by us for the periods indicated:

   
Partnership
    
Predecessor
  
   
Year Ended
    
December 22 to
    
January 1 to
    
Year Ended
  
   
December 31,
    
December 31,
    
December 21,
    
December 31,
  
   
2011
    
2010
    
2010
    
2009
  
Acquisition of oil and natural gas properties:
                        
Proved
   $ -     $ 82,781     $ 872,829     $ 49,145  
Unproved
     -       -       43,000       -  
Development costs
     64,027       357       60,567       7,152  
Total
   $ 64,027     $ 83,138     $ 976,396     $ 56,297  

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, 2011, 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, 2011 ,2010 and 2009.

Oil and Gas Reserve Quantities. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made.


Prices include consideration of changes in existing prices provided only by contractual arrangement, but not on escalations based on future conditions. All of the Partnership’s oil and natural gas producing activities were conducted within the continental United States.

Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as “proved developed reserves” only after testing by a pilot project or after the operations of an installed program has confirmed through production response that the increased recovery will be achieved.

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 for the periods indicated:

   
Oil
(MBbl)
    
Natural
Gas
(MMcf)
    
NGL
(MBbl)
  
Partnership:
                  
Balance, December 22, 2010
     -       -       -  
Contribution from Predecessor (1)
     25,800       242,237       1,447  
Acquisition of reserves
     6,532       1,538       -  
Production
     (49 )     (510 )     (4 )
Balance, December 31, 2010
     32,283       243,265       1,443  
Extensions
     1,274       677       110  
Revision of previous estimates
     2,459       (28,463 )     6,554  
Production
     (1,766 )     (16,925 )     (263 )
Balance, December 31, 2011
     34,250       198,554       7,844  
                         
Proved developed reserves:
                        
December 31, 2010
     19,588       178,657       1,389  
December 31, 2011
     21,457       142,428       6,082  
                         
Predecessor:
                        
Proved reserves:
                        
Balance, December 31, 2008
     8,182       34,743       -  
Purchases of reserves in place
     262       20,169       1,327  
Sale of reserves in place
     (442 )     (5,981 )     -  
Revisions of previous estimates
     1,045       1,760       966  
Production
     (739 )     (5,359 )     (207 )
Balance, December 31, 2009 (2)
     8,308       45,332       2,086  
Purchases of reserves in place
     21,890       243,835       2,592  
Revisions of previous estimates
     5,653       (1,050 )     244  
Production
     (2,172 )     (14,753 )     (282 )
Balance, December 21, 2010 (3)
     33,679       273,364       4,640  
                         
Proved developed reserves:
                        
December 31, 2009
     6,721       44,879       2,037  
December 21, 2010
     24,313       198,160       4,411  
 

(1) These reserves include 12,798 MBbl, 185,706 MMcf, and 84 MBbl of Oil, Natural Gas and NGLs associated with the acquisition assets the Partnership acquired from the Fund in October 2011. The acquisitions of these assets were accounted for as transactions between entities under common control, whereby the Partnership’s historical financial information and proved reserve volumes have been revised to include balances and activity related to the acquired properties as if the Partnership owned them for all periods presented by the Partnership, including the period from December 22, 2010 to December 31, 2010 and the year ended December 31, 2011.

(2) 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.

(3) 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.

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.

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.

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 $96.19/Bbl for oil and $4.12/MMbtu for natural gas as of December 31, 2011; $74.52/Bbl for oil and $4.53/MMbtu for natural gas as of December 31, 2010 and the unweighted arithmetic average first-day of-the-month prices for the prior 12 months were $61.18/Bbl for oil and $3.87/MMbtu for natural gas as of December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2011, the relevant average realized prices for oil, natural gas and NGLs were $90.89 per Bbl, $4.28 per Mcf and $49.23 per Bbl.  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.


The estimated standardized measure of discounted future net cash flows relating to our proved reserves is shown below for the periods indicated:

   
Partnership
    
Predecessor
  
   
December 31,
    
December 31,
    
December 21,
    
December 31,
  
   
2011
    
2010
    
2010 (1)
    
2009 (2)
  
Future cash inflows
   $ 4,349,712     $ 3,617,951     $ 4,019,453     $ 707,028  
Future production and development costs
     (1,892,789 )     (1,562,104 )     (1,790,043 )     (319,391 )
Future net cash flows
     2,456,923       2,055,847       2,229,410       387,637  
10% annual discount for estimated timing of cash flows
     (1,284,382 )     (1,059,267 )     (1,092,216 )     (170,762 )
Standardized measure of discounted future net cash flows
   $ 1,172,541     $ 996,580     $ 1,137,194     $ 216,875  

(1)  This standardized measure of discounted cash flows includes $1.1 million attributable to an approximate 94.3% noncontrolling interest in the Predecessor.

(2)  This standardized measure of discounted cash flows includes $202.1 million  attributable to an approximate 93.2% noncontrolling interest in the Predecessor.

The above table does not include the effects of income taxes on future net revenues because during 2011, 2010 and 2009, 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
    
Predecessor
  
   
Year Ended
    
December 22 to
    
January 1 to
    
Year Ended
  
   
December 31,
    
December 31,
    
December 21,
    
December 31,
  
   
2011
    
2010
    
2010
    
2009
  
Beginning of period
   $ 996,580     $ -     $ 216,875     $ 131,584  
Contribution from Predecessor
     -       912,313       -       -  
Purchases of reserves in place
     -       -       836,500       51,202  
Sale of reserves in place
     -       -       -       (10,106 )
Acquisition of reserves
             88,573       -       -  
Extensions
     26,016       -       -       -  
Revisions of previous estimates
     66,579       -       77,585       33,930  
Changes in future development cost, net
     (50,872 )     -       (50,731 )     3,149  
Development cost incurred during the year
                                
that reduce future development costs
     9,598       -       1,882       1,853  
Net change in prices
     192,290       -       73,352       51,552  
Sales, net of production costs
     (169,846 )     (4,306 )     (150,403 )     (23,724 )
Changes in timing and other
     2,538       -       110,446       (35,723 )
Accretion of discount
     99,658       -       21,688       13,158  
End of period
   $ 1,172,541     $ 996,580     $ 1,137,194     $ 216,875  


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 the dates indicated:

   
2010
    
2009
  
Proved properties
   $ 26,704     $ 12,020  
Less: Accumulated depreciation,depletion, amortization and impairment
     (7,187 )     (3,705 )
Proved properties, net
     19,517       8,315  
Unproved properties
     1,067       268  
Total 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 indicated:

   
2010
    
2009
  
Development costs
   $ 14,631     $ 2,787  
Asset 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
    
2009
  
   
Oil
    
Gas
    
Oil
    
Gas
  
   
(MBbl)
    
(MMcf)
    
(MBbl)
    
(MMcf)
  
Proved reserves:
                        
Balance, beginning of period
     1,003       2,603       227       900  
Recapitalization of Ute Energy, LLC
     (140 )     (529 )     -       -  
Extensions, discoveries and other additions
     1,117       2,552       281       660  
Divestiture of reserves
     -       -       (1 )     (38 )
Revisions of previous estimates
     (124 )     (205 )     551       1,274  
Production
     (123 )     (296 )     (55 )     (193 )
Balance, end of period
     1,733       4,125       1,003       2,603  
Proved developed reserves:
                                
End of period
     611       1,686       283       1,078  
 

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
    
2009
  
Future cash inflows
   $ 132,914     $ 57,291  
Future production costs
     (59,674 )     (23,008 )
Future development costs
     (27,886 )     (15,711 )
Future net cash flows
     45,354       18,572  
10 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 ended
  
   
December 31,
  
   
2010
    
2009
  
Standardized measure of discounted future net cash flows, beginning of period
   $ 8,947     $ 3,514  
Recapitalization 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       2,952  
Revisions of previous quantity estimates
     (964 )     2,374  
Net changes in prices and production costs
     5,196       192  
Previously estimated development costs incurred during the period
     1,779       -  
Changes in estimated future development costs, net
     1,344       210  
Development costs incurred during the year that reduce future development costs
     -       106  
Sales of reserves in place
     -       (65 )
Change in production rates (timing) and other
     2,499       653  
Accretion of discount
     703       351  
Standardized measure of discounted future net cash flows, end of period
   $ 26,824     $ 8,947  


SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

In October 2011, the Partnership acquired the Transferred Properties from the Fund. Because these assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, whereby the assets and liabilities of the acquired properties were recorded at the Fund’s carrying value and the Partnership’s historical financial information was revised to include the acquired properties for all periods in which the properties were owned by the Fund. Accordingly, the above selected quarterly financial data for the Partnership reflects the historical results of the Partnership combined with those of the acquired assets.

Quarterly financial data was as follows for the periods indicated:

   
Partnership
  
   
First
    
Second
    
Third
    
Fourth
  
   
Quarter (1)
    
Quarter (2)(3)
    
Quarter (4)(5)
    
Quarter (6)
  
2011
                        
Revenues
   $ 62,831     $ 67,880     $ 64,781     $ 64,376  
Gross profit (7)
     43,033       46,642       40,620       41,516  
Operating income
     16,927       18,865       11,598       11,699  
Net (loss) income
     (46,549 )     28,988       105,165       (26,467 )
Limited partners' interest in net (loss) income       (29,319 )       15,915        51,878        (26,467 ) 
Net (loss) income per limited partner unit    $   (0.82 )   $   0.44     $   1.45     $   (0.98 ) 
                                 
2010
                                
Revenues
                           $ 6,685  
Gross profit
                             4,330  
Operating income
                             1,360  
Net loss
                             (12,067 )
Limited partners' interest in net loss                               (7,092 )
Net loss per limited partner unit                            $   (0.21 ) 
 
 
(1)
The first quarter results were impacted due to revisions from the Transferred Properties with an increase in net loss of $17.2 million comprising of increases of $32.1 million in revenues, $21.0 million in gross margin (including $8.0 million of production expense), $7.2 million in operating income, $22.8 million in unrealized losses on commodity derivatives.
 
(2)
The three month second quarter results were impacted due to revisions from the Transferred Properties with an increase in net income of $13.1 million comprising of increases of $36.2 million in revenues, $23.8 million in gross margin (including$9.3 million of production expense), $8.3 million in operating income, and $12.9 million in unrealized gains on commodity derivatives.
 
(3)
The six months ended June 30, 2011 results were impacted due to revisions from the Transferred Properties with an increase in net loss of $4.1 million comprising of increases of $68.3 million in revenues, $44.8 million in gross margin (including $17.3 million in production expense), $15.5 million in operating income, and $9.9 million in unrealized losses on commodity derivatives.
 
(4)
The three months third quarter results were impacted due to revisions from the Transferred Properties with an increase in net income of $53.2 million comprising of increases of $36.1 million in revenues, $22.8 million of gross margin (including $10.0 million in production expense), $6.0 million in operating income, $100.2 million in unrealized gains on derivative commodity contracts, and $42.7 million of realized losses on commodity derivatives.
 
(5)
The nine months ended September, 30, 2011 results were impacted due to revisions from the Transferred Properties with an increase in net income of $49.1 million comprising of increases of $104.4 million in revenues, $67.6 million in gross margin (including $27.4 million in production expense), $21.5 million in operating income, $90.3 million in unrealized gains on commodity derivatives, and $42.7 million of realized losses on commodity derivatives.
 
(6)
Fourth quarter 2010 results for the Partnership include results for the 10-day period from December 22 to December 31, 2010 for the IPO Assets and Transferred Properties.
 
(7)
 Represents total revenues less productions expenses.
 

   
Predecessor
  
   
First
    
Second
    
Third
    
Fourth
  
   
Quarter
    
Quarter
    
Quarter
    
Quarter (1)
  
2010
                        
Revenues
   $ 35,633     $ 55,359     $ 84,478     $ 77,916  
Gross profit
     21,318       32,417       53,179       38,064  
Operating income
     8,803       8,614       13,441       1,437  
Net income (loss)
     9,176       43,291       (1,486 )     (19,068 )

 
(1)
Fourth quarter 2010 results include only 82 days of operations of the IPO Assets under the Predecessor as these assets were owned by the Partnership for the remaining 10 days of the fourth quarter of 2010.
 
 
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