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Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2012

Basis of Presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2012 and 2011. These financial statements also include the results of our operations and cash flows for the years ended December 31, 2012 and 2011, the period of December 22 to December 31, 2010 and those of our Predecessor for the period of January 1, 2010 to December 21, 2010, and changes in partners’ capital for the years ended December 31, 2012 and 2011 and for the period from December 22 to December 31, 2010. These consolidated financial statements include our subsidiaries and all of the subsidiaries of the Predecessor.

Our consolidated statement of operations and consolidated statement of cash flows for the period from December 22 to December 31, 2010 reflect activity since the IPO 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 statement 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 2012 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 31.7% limited partner interests in us, including all preferred 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 previously issued financial statements to include the activities of the October 2011 Transferred Properties and the December 2012 Transferred Properties as if they were acquired by the Partnership from the date of our IPO.

The Partnership’s financial statements have been prepared in this annual report on Form 10-K to include the results attributable to the October 2011 Transferred Properties and the December 2012 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 years ended December 31, 2011 and 2012 as the transactions were between entities under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the October 2011 Transferred Properties and the December 2012 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 October 2011Transferred Properties and the December 2012 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, 2011 was impacted based on revisions from the December 2012 Transferred Properties with an increase in total assets of $97.3 million comprising of an increase in noncurrent assets. Total liabilities and partners’ capital was also increased by $97.3 million comprising increases of $149.4 million in noncurrent liabilities and decreases of $52.1 million in predecessor’s capital.

Revised Statement of Operations

Our statement of operations for the year ended December 31, 2012 was impacted by the December 2012 Transferred Properties resulting in an increase in net income of $37.3 million comprising increases of $109.3 million in revenues, $69.7 million in operating expenses (including $41.5 million in production expenses and $28.1 million in other operating expenses), $2.4 million in unrealized gains on commodity derivatives and $4.7 million in interest expense.

Our historical statement of operations for the year ended December 31, 2011 was impacted based on revisions from the December 2012 Transferred Properties with an increase in net income of $27.2 million comprising increases of $101.1 million in revenues, $68.3 million in operating expenses (including $44.2 million in production expenses and $24.1 million in other operating expenses), $0.6 million in unrealized losses on commodity derivatives and $5.0 million in interest expense.

Our historical statement of operations for the period from December 22, 2010 to December 31, 2010 was impacted based on revisions from the December 2012 Transferred Properties with a decrease in net loss of less than $0.1 million comprising increases of $2.3 million in revenues, $1.8 million in operating expenses (including $1.1 million in production expenses and $0.7 million in other operating expenses), $0.3 million in unrealized losses on commodity derivatives and $0.1 million in interest expense.

Use Of Estimates

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;

·	Unit based compensation;

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

·	Natural gas imbalances.

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

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

Cash And Cash Equivalents

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 a major financial institution in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We use the specific identification method of providing allowances for doubtful accounts. As of December 31, 2012 and 2011, the allowance for doubtful accounts was not

Property And Equipment

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.

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

There were no write-downs required by us during the years ended December 31, 2012 and 2011 or the period from December 22, 2010 to December 31, 2010. No write-down was required by the Predecessor for the period from January 1, 2010 to 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.

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.

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

Transactions Between Entities Under Common Control

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

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

Long-Term Debt Assumed. The historical book value and related activity of long-term debt assumed from the Predecessor was determined by using the effective date amount of debt assumed per the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. The Partnership’s financial statements include the beginning IPO Closing Date balance, borrowings and repayments of the assumed debt to properly reflect these debt transactions as if the Partnership owned the October 2011 Transferred Properties and the December 2012 Transferred Properties for the periods presented by the Partnership.

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

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

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

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

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

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

Business Combinations

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

Oil And Gas Reserve Quantities

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 reserve engineers also adhere 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 7 – Asset Retirement Obligation.

Deferred Financing Costs

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

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 5 – Fair Value Measurements and Note 6 – Derivative Activities.

Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The credit worthiness of the counterparties is subject to continual review. We believe the risk of nonperformance by our counterparties is low. Full performance is anticipated, and we have no past-due balances from our counterparties. In addition, although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have properly presented all asset and liability positions without netting. See Note 6 – Derivative Activities.

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, 2012 or 2011, with the exception of an environmental liability acquired in the Prize Acquisition. See Note 9 – Commitments and Contingencies for further details.

Concentrations Of Credit And Market Risk

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 2012, we evaluated our concentration of credit risk by evaluating transactions from our assets as if we owned the December 2012 Transferred Properties for the entire year. This analysis of our revenue process resulted in three customers accounting for 12%, 13% and 33% of our oil, natural gas and NGL revenues.

In 2011, we evaluated our concentration of credit risk by evaluating transactions from our assets as if we owned the October 2011 Transferred Properties and the December 2012 Transferred Properties for the entire year. This analysis of our revenue process resulted in three customers accounting for 11%, 12%, and 29% 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, October 2011 Transferred Properties and the December 2012 Transferred Properties for the entire year. This analysis of our revenue process resulted in two customers accounting for 23% and 34% 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.

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

There was no beneficial conversion feature as our common units were trading below the $21.27 per unit fair value of the Preferred Units as of December 31, 2012.

Revenue Recognition

Revenues from oil, NGL and gas sales are recognized upon delivery and passage of title when evidence of arrangement exists and collectability is reasonably assured. Gas imbalances are recognized using the sales method, net of any royalty interests or other profit interests in the produced product. Revenues from natural gas production may result in more or less than our pro rata share of production from certain wells. Under the sales method for natural gas sales and natural gas imbalances, when our sales volumes exceed our entitled share and the overproduced balance exceeds our share of remaining estimated proved natural gas reserves for a given property, we record a liability. See Note 13 – Accrued and Other Liabilities.

General And Administrative Expenses

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 Services Agreement as defined in Note 15 – Related Party Transactions. The administrative services fee, as discussed in Note 15 – Related Party Transactions, 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, the Partnership will be required to reimburse QRM for its share of allocable general and administrative expenses based on the estimated use of such services.

Our potential sources of general and administrative expenses through December 31, 2012, 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”).

Through 2012, our general and administrative expenses, for any quarter therein, were comprised of Direct G&A, the administrative service fee and Allocated G&A in excess of the administrative service fee. We were not 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.

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.

Beginning on January 1, 2013, our general and administrative expenses for each quarter will comprise of Direct G&A and Allocated G&A. The allocated G&A will be based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. The fee will include direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If the Fund raises a second fund, the quarterly administrative services costs will be further divided to include the second fund as well.

Management Incentive Fee

Under our partnership agreement, as amended, for each quarter for which we pay distributions that are equal or greater than 115% of our minimum quarterly distribution (which we refer to as our “Target Distribution”), QRE GP will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of a management incentive fee base. With the expiration of the subordination period on December 22, 2012 and having received three full quarters of management incentive fees, QRE GP became eligible to convert up to 80% of its fourth quarter 2012 management incentive fee for 6,133,558 Class B units. On February 22, 2013, QRE GP elected to convert 80% of their fourth quarter management incentive fee and, on March 4, 2013, received 6,133,558 Class B units. The calculation of the management incentive fee and conversion and the current year expense is discussed further in Note 15 – Related Party Transactions 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 the Texas Margin tax and our income taxes are entirely attributable to the Texas Margin Tax which is derived from our taxable income apportioned to Texas. We recorded a deferred tax asset of $0.3 million and $0.3 million related to our operations located in Texas as of December 31, 2012 and 2011 and a deferred tax liability of $0.4 million and less than $0.1 million as of December 31, 2012 and 2011. The deferred tax asset and deferred tax liability are presented net as a deferred tax liability of $0.1 million on the consolidated balance sheet as of December 31, 2012 and as a deferred tax asset of $0.3 million on the consolidated balance sheet as of December 31, 2011. Our provision for income taxes was a net expense of $0.5 million and $0.9 million for years ended December 31, 2012 and 2011 and a net benefit of $0.1 million for the period December 22 to December 31, 2010.

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.

Net Income (Loss) Per Limited Partner Unit

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 years ended December 31, 2012 and 2011, and the period from December 22, 2010 to December 31, 2010. Income from the October 2011 Transferred Properties and the December 2012 Transferred Properties is excluded from the calculation of net income (loss) per limited partner as the income relates to the Predecessor operations. The Preferred Units and the management incentive fee, to the extent eligible for conversion into Class B units, are contingently convertible and will be included in the denominator for diluted income per unit unless they are anti-dilutive. See Note 11 – Net Income (Loss) Per Limited Partner Unit.

Fair Value Of Financial Instruments

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt. The carrying amounts of our financial instruments other than derivatives and long-term debt approximate fair value because of the short-term nature of the items. Derivatives are recorded at fair value. The carrying value of our debt under the Revolving Credit Facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. The Senior Notes are recorded at historical cost. See Note 5 – Fair Value Measurements.

Business Segment Reporting

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

Equity-Based Compensation

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

As of December 31, 2012 and 2011, we have granted awards to employees of QRM who performed services for us. We record these compensation costs as direct general and administrative expenses. See Note 12 – Equity Based Compensation.

Recent Accounting Pronouncements

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 it did not have a material impact on our financial position, results of operations or cash flows; however, additional disclosures were added to Note 5 – Fair Value Measurements.

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.

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

Predecessor [Member]

Management Incentive Fee

Management Fees

The Predecessor paid 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 16 – Predecessor’s Unconsolidated Investment in Ute Energy, LLC.

Equity-Based Compensation

The Predecessor has various forms of equity-based and liability-based compensation outstanding under its employee compensation plan. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period. Awards classified as liabilities are revalued at each reporting period and changes in the fair value of the options are recognized as compensation expense over the vesting periods of the awards. See Note 12 – Equity-Based Compensation for further information.

Employee Benefit Plan

The Predecessor has a 401(k) savings plan available to all eligible employees. The Predecessor matches 100% of employee contributions up to a certain percentage of the employee’s salary. Matching contributions vest immediately.