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 DebtAssumed 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.