ex99_6.htm

EX-99.6 7 ex99_6.htm EXHIBIT 99.6 ex99_6.htm

Exhibit 99.6

Report of Independent Auditors

To the Board of Directors

QA Global GP, LLC:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statement of operations, of changes in partners' capital and of cash flows present fairly, in all material respects, the financial position of QA Holdings, LP and its subsidiaries (the Partnership) at December 31, 2010, and December 31, 2009, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. 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

June 7, 2011

QA HOLDINGS, LP

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	47,204		$	17,156
Accounts receivable:
Trade and other, net of allowance for doubtful accounts		4,853			2,796
Oil and gas sales		33,805			10,573
Due from affiliates		3,610			-
Derivative instruments		8,223			7,783
Prepaid and other current assets		2,323			2,533
Total current assets		100,018			40,841
Noncurrent assets:
Oil and gas properties, using the full cost method of accounting		1,038,901			709,552
Gas processing equipment		7,605			4,386
Furniture, equipment, and other		4,685			3,959
Less accumulated depreciation, depletion, amortization and impairment		(374,197	)		(592,254	)
Total property and equipment, net		676,994			125,643
Equity investments		158,362			41,597
Derivative instruments		28,997			-
Other long-term assets		26,735			18,689
Total noncurrent assets		891,088			185,929
Total assets	$	991,106		$	226,770
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable	$	146		$	1,845
Oil and gas sales payable		19,173			8,578
Current portion of asset retirement obligations		2,318			2,250
Derivative instruments		40,540			14,484
Accrued and other liabilities		64,374			13,758
Total current liabilities		126,551			40,915
Noncurrent liabilities:
Long-term debt		380,081			86,450
Derivative instruments		61,018			52,998
Asset retirements obligations		49,133			32,994
Other long-term liabilities		7,552			101
Total noncurrent liabilities		497,784			172,543
Owners' equity:
Partners' capital		13,763			(1,421	)
Noncontrolling interest		353,008			14,733
Total owners' equity		366,771			13,312
Total liabilities and owners' equity	$	991,106		$	226,770

See accompanying notes to the consolidated financial statements

QA HOLDINGS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

	YearEnded December 31,
	2010			2009
Revenues:
Oil, natural gas and natural gas liquids sales	$	251,846		$	69,193
Processing and other		9,061			3,608
Total revenues		260,907			72,801
Operating Expenses:
Production expenses		111,431			44,841
Impairment of oil and gas properties		-			28,338
Depreciation, depletion and amortization		68,400			16,993
Accretion of asset retirement obligations		3,786			3,585
Management fees		10,799			12,018
Acquisition evaluation costs		1,192			582
Offering costs		5,148			-
General and administrative		26,208			18,697
Bargain purchase gain		(4,492	)		(1,200	)
Other expense		224			-
Total operating expenses		222,696			123,854
Operating income (loss)		38,211			(51,053	)
Other Income (Expense):
Equity in (losses) earnings		(69	)		2,675
Dividends on investment in marketable equity securities		-			233
Gain on investment in marketable equity securities		-			394
Gain (loss) on commodity derivative contracts		1,679			(63,120	)
Gain on equity investment share issuance		4,064			-
Interest expense, net		(26,422	)		(3,716	)
Other income (expense)		482			(645	)
Total other expense		(20,266	)		(64,179	)
Income (loss) before income taxes		17,945			(115,232	)
Income tax expense		(108	)		(182	)
Net income (loss)		17,837			(115,414	)
Net income (loss) attributable to noncontrolling interest		16,650			(107,528	)
Net income (loss) attributable to controlling interest	$	1,187		$	(7,886	)
General partners' interest in net income (loss)	$	12		$	(79	)
Limited partners' interest in net income (loss)	$	1,175		$	(7.807	)

See accompanying notes to the consolidated financial statements

QA HOLDINGS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY

(In thousands)

	General Partner			Limited Partners			Total Partners' Capital			Noncontrolling Interest			Total Equity
Balances - December 31, 2008	$	59		$	5,898		$	5,957		$	133,978		$	139,935
Contributions by partners		14			1.427			1,441			14,550			15,991
Distributions to partners		(9	)		(924	)		(933	)		(26,267	)		(27.200	)
Net loss		(79	)		(7,807	)		(7,886	)		(107,528	)		(115,414	)
Balances - December 31, 2009		(15	)		(1,406	)		(1,421	)		14,733			13,312
Contributions by partners		143			14,109			14,252			460,802			475,054
Distributions to partners		(216	)		(21,370	)		(21,586	)		(308,414	)		(330,000	)
Share-based compensation		16			1,619			1,635			-			1,635
Excess consideration over contribution of net assets to affiliated company		197			19,499			19,696			169,237			188,933
Net income		12			1,175			1,187			16,650			17.837
Balances -December 31, 2010	$	137		$	13,626		$	13,763		$	353,008		$	366,771

See accompanying notes to the consolidated financial statements

QA HOLDINGS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	17.837		$	(115,414	)
Adjustments to reconcile net income (loss) to net cash provided (used in) by operating activities:
Depreciation, depletion and amortization		68,400			16,993
Accretion of asset retirement obligations		3.786			3,585
Non cash general and administrative expense included in equity earnings		(101	)		-
Amortization of deferred financing costs		6,480			627
Amortization of liability and equity awards		3,533			-
Impairment of oil and gas properties		-			28,338
Amortization of costs of derivative instruments		-			1,219
Unrealized losses on derivative contracts		6,065			108,164
Unrealized gains on investment in marketable equity securities		-			(5,640	)
Realized losses on investment in marketable equity securities		-			5,246
(Gain) loss on disposal of furniture, fixtures and equipment		(482	)		723
Bargain purchase gain		(4,492	)		(1.200	)
Equity in earnings of unconsolidated entities		69			(2,675	)
Gain on equity share issuance		(4,064	)		-
Changes in operating assets and liabilities:
Accounts receivable and other assets		(24,387	)		15,052
Accounts payable and other liabilities		42,405			9,889
Net cash provided by operating activities		115,049			64,907
Cash flows from investing activities:
Additions to oil and gas properties		(56,172	)		(31,278	)
Acquisition of oil and gas properties		(954,196	)		(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
Proceeds from sale of properties		-			16,287
Proceeds received concurrent with contribution of net assets to QRE		300,000			-
Net cash used in investing activities		(711,242	)		(55,458	)
Cash flows from financing activities:
Contributions by partners and non-controlling interest owners		475,054			15,991
Distributions to partners and non-controlling interest owners		(330,000	)		(27,019	)
Proceeds from bank borrowings		607,383			33,000
Repayments on bank borrowings		(113,752	)		(35,300	)
Deferred financing costs		(12,444	)		-
Net cash provided by (used in) financing activities		626,241			(13,328	)
Increase (decrease) in cash and cash equivalents		30,048			(3,879	)
Cash and cash equivalents at beginning of period		17,156			21,035
Cash and cash equivalents at end of period	$	47,204		$	17,156

See accompanying notes to the consolidated financial statements

QA Holdings, 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 - DESCRIPTION OF BUSINESS

QA Holdings, LP (QAH or the Partnership), a Delaware limited partnership, commenced operations on April 1, 2006 for the primary purpose of acquiring, owning, enhancing and producing oil and gas properties through its subsidiaries. QAH's ownership interest in these subsidiaries ranges from 3% to 100%. QAH is deemed to have effective control of all of these subsidiaries and, therefore, the accounts of all of its subsidiaries are included in the accompanying consolidated financial statements. At December 31, 2010, the Partnership owns properties located in Alabama, Arkansas, Florida, Kansas, Louisiana, Mississippi, New Mexico, Oklahoma, and Texas.

QA Global GP, LLC (QA Global) is the general partner of and owns a 1% interest in QAH. The limited partners of QAH are QR Holdings, LP (QR), Aspect Asset Management, and members of management of QAH.

The following subsidiaries are wholly owned by QAH:

Black Diamond Resources, LLC (Black Diamond)

Black Diamond Resources 2, LLC

Black Diamond GP, LLC

QA GP, LLC (QA GP)

Quantum Resources Management, LLC (QRM)

QAB Carried WI, LP (QAB)

QAC Carried WI, LP (QAC)

QRFC, LP (QRFC)

QR Ute Partners (QR Ute)

The following subsidiaries are not wholly owned but are deemed to be under QAH's effective control with the ownership percentages listed below:

	General Partner	Ownership Percentage		Limited Partners	Ownership Percentage
Quantum Resources Al, LP (QRA1)	QAP	3	%	Other	97	%
Quantum Resources B, LP (QRB)	QAP	3	%	Other	97	%
Quantum Resources C, LP (QRC)	QAP	3	%	Other	97	%
Quantum Aspect Partnership (QAP)	QA GP	1	%	Other	99	%

The entities listed above comprise Quantum Resources Fund (the Fund). The Fund's objective is to acquire and enhance mature, long-lived oil and gas producing assets. The Fund is managed by QA Asset Management, LLC (QAAM), an affiliated entity. Quantum Aspect Partnership (QAP) is the general partner of the investor limited partnerships QRA1, QRB and QRC, (collectively, the LP's). The LP's pay management fees to QAAM as specified in the respective partnership agreements. QAP receives, after the limited partners have recovered their initial investment and a preferred rate of return, participation in an additional 14% of cash flows generated by the LP's.

Certain of the above subsidiary limited partnerships, including QRA1, QRB, QRC, QAB, QAC and Black Diamond, also comprise the MLP Fund (the MLP Fund). The MLP Fund is managed by QRM.

The Partnership also has an equity investment in QR Energy, LP (QRE), a limited partnership formed in September 2010 by affiliates of the Partnership. QRE was formed to receive certain of the assets of the Partnership. In connection with QRE's initial public offering (the IPO) in December 2010, the MLP Fund: (i) conveyed interests in certain oil and gas properties and certain other assets and liabilities to QRE in exchange for cash and units (See Note 4), and (ii) entered into services and omnibus agreements (See Note 15).

Oil and gas properties are initially acquired by QAP or QRM and ownership interests are subsequently assigned to the entities in the Fund based on the relative contributed capital of each entity. Based on current relative capital contributions, ownership of properties acquired is allocated approximately as follows:

Entity	Ownership Percentage
QRA I		93	%
QAB		2	%
QAC		3	%
Black Diamond		2	%

QAH and QA Global are managed by QAAM.

QRM provides personnel and services to the LP's and Black Diamond. QRM also provides personnel and services to QRE and its subsidiaries. The pro-rata cost of these services is allocated to these entities based on their relative property ownership.

The LP's each have a 12-year term, which can be extended for two one-year periods. Under the partnership agreements, any funding of the partners' equity commitments is to be completed within five years of the commencement date. The partnership agreements provide that the general partner and its affiliates contribute an amount equal to 3% of the LP's contributions and purchase a 2% interest in each property in the name of Black Diamond. Black Diamond also receives an additional 2% carried interest from QRA1 in the properties acquired.

QRB provides funding to QAB, which then acquires a working interest in the properties. In exchange for the funding provided, QRB receives a net profits interest in those same properties.

QRC provides funding to QAC, which then acquires a working interest in the properties. In exchange for the funding provided, QRC receives a net profits interest in those same properties.

QRFC's primary purpose is to raise funds through debt financing and subsequently invest those funds in QRC, an affiliated entity. QRFC's investment is a preferred limited partnership interest that is senior to the other limited partnership interest. QRFC earns a return equal to the British Banker's Association London Interbank Offered Rate (LIBOR) plus 2% per annum on its investment in QRC. All cash available to QRC shall first be paid to QRFC until an amount equal to any cumulative distributions due has been paid. As of December 31, 2010, QRFC has $11.2 million invested in QRC. As of December 31, 2010, QRFC had earned a return equal to approximately $924,000 and received distributions of approximately $839,000 on its investment in QRC. The remaining 2010 earned distribution of approximately $85,000 was paid in February 2011.

The LP's have received subscriptions for limited partnership interests from their limited partners totaling approximately $1.2 billion to date through December 31, 2010. QAP, the general partner of the LP's, has made an equity commitment of $36.1 million, which represents 3% of the total equity commitments received. The limited partnership agreements with the LP's provide that QAP can request funding of equity commitments with a minimum 10 business days notice. As of December 31, 2010, QAP and the LP's had funded $1.1 billion of their equity commitments. For the years ended December 31, 2010 and 2009, there were distributions paid to QAP and the LP's of $330.0 million and $27.2 million.

The LPs limited partnership agreements provide that they will pay organization costs and costs paid to third parties for services in connection with obtaining funding commitments from the limited partners (placement agent fees). The LP's combined are responsible for organization costs up to a limit of $1.5 million. Any costs in excess of this amount are paid by the partnerships; however, the management fees paid to QAAM are reduced by a corresponding amount.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

Reclassifications and Revisions

Certain prior period amounts have been reclassified to conform to the 2010 presentation. These reclassifications do not affect the totals for current assets, current liabilities, noncurrent assets, noncurrent liabilities, operating expenses, other income (expenses), net income or cash flows.

The Partnership determined that "Proceeds from sales of marketable equity securities" in the amount of $6.2 million as previously presented within cash flows from operating activities, should have been presented within cash flows from investing activities for the year ended December 31, 2009. The Partnership evaluated the impact of this adjustment and concluded that this item was not material to the statement of cash flows for such period. The Partnership has, however, chosen to revise its statement of cash flows to reclassify $6.2 million from cash flows from operating activities to cash flows from investing activities.

During 2010, the Partnership 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 Partnership 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.

During 2010, the Partnership determined that it had overpaid QAAM by a total of $0.8 million related to management fees, spread ratably over the last four years since inception in 2006. Accordingly, this amount was repaid in the third quarter of 2010 and the management fee has been reversed during the year ended December 31, 2010 as a reduction of this operating 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.

Marketable Securities

The Partnership defines marketable securities as securities that can be readily converted into cash. Examples of marketable securities include U.S. government obligations, commercial paper, corporate notes and bonds, certificates of deposit and equity securities. Investments in marketable securities that are classified as trading are measured subsequently at fair value in the statement of financial position with the unrealized holding gains and losses reflected in earnings. Available-for-sale investments are initially recorded at cost and periodically adjusted to fair value and the changes are reflected in comprehensive income. Realized gains and losses and declines in value judged to be other than temporary are determined based on the specific identification method and are included in earnings. The Partnership determines the appropriate classification of securities at the time of purchase and reevaluates such classification as of each balance sheet date.

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. At December 31, 2010 and 2009, the allowance for doubtful accounts was $0.7 million and $0.2 million

Property and Equipment

Oil and Gas Properties

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

Ceiling Test

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

Prior to December 31, 2009, the ceiling calculation dictated that prices and costs in effect as of the last day of the quarter be held constant. The current ceiling calculation utilizes prices calculated as a twelve-month average price using first day of the month prices and costs in effect as of the last day of the quarter are held constant. Under both of these methods, the prices used are adjusted for basis or location differentials, product quality, energy content and transportation fees. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date. There was no write-down required as of December 31, 2010. During 2009, the Partnership recognized a ceiling test impairment of oil and gas properties of $28.3 million.

Depletion

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

Gas processing plants are not considered a part of the full-cost pool and the provision for depreciation of these assets is calculated using the straight-line method over estimated useful lives of eight to twenty years. The provision for depreciation of the furniture and fixtures and computer hardware and software is calculated using the straight-line method over estimated useful lives of the assets ranging from three to five years.

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 report a gain or loss to the extent the actual costs differ from the recorded liability. See Note 10.

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. See Note 7.

Derivatives

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

We have elected not to designate our derivatives as hedging instruments. Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Gains and losses on derivatives, including realized and unrealized gains and losses, are reported as nonoperating income (loss) on the statements of operations in "gains (losses) on commodity derivatives." Realized gains (losses) represent amounts related to the settlement of commodity derivatives which are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are noncash items.

Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. All of our derivatives as of December 31, 2010 are with parties who are also lenders under our credit facility. The credit worthiness of the counterparties is subject to continual review. We believe the risk of nonperformance by our counterparties is low. Full performance is anticipated, and we have no past-due balances from our counterparties. In addition, although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have properly presented all asset and liability positions without netting. See Note 9.

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. The Partnership closely monitors known and potential legal, environmental, and other contingencies and periodically determines when the Partnership should record losses for these items based on information available.

Concentrations of Credit Risk

Credit Risk

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

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

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

	2010			2009
Shell Trading US Company		45	%		24	%
Sunoco Inc R&M		10	%		12	%
Plains Marketing LP		0	%		10	%

Because there are numerous other parties available to purchase the Partnership's oil and gas production, the Partnership believes that the loss of any individual purchaser would not materially affect its ability to sell its natural gas or crude oil production.

Market Risk

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

Revenue Recognition

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers. Revenues from natural gas production may result in more or less than our pro rata share of production from certain wells. Under the sales method for natural gas sales and natural gas imbalances, when our sales volumes exceed our entitled share and the overproduced balance exceeds our share of remaining estimated proved natural gas reserves for a given property, we record a liability. See Note 13.

As of December 31, 2010 and 2009, the gas imbalance liability was $5.0 million and $0.8 million.

General and Administrative Expenses

Pursuant to the Services Agreement with QRE (see Note 15), the Partnership provides administrative and acquisition advisory services necessary to allow QRE's general partner to manage, operate and grow QRE's business.

The term of the Services Agreement comprises an initial term from December 22, 2010 to December 31, 2012 and continues on a year-to-year basis thereafter unless terminated after the initial term by the Partnership or QRE.

Under the Services Agreement, from the closing of the IPO through December 31, 2012, the Partnership will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by QRE during the preceding quarter, calculated prior to the payment of the fee. For the period from the closing of the QRE's IPO through December 31, 2010, the Partnership charged approximately $0.1 million for the administrative services fee under the Services Agreement, and recognizes the fee as a reduction of operating expenses.

During the term of the Services Agreement, the Partnership will not be reimbursed by QRE for any direct or indirect general and administrative expenses relating to QRE in excess of the administrative service fee. For the period from the closing of QRE's IPO through December 31, 2010, these general and administrative expenses applicable to QRE totaled $0.2 million.

After the term of the Services Agreement ends, in lieu of the quarterly administrative services fee, the Partnership will be reimbursed by QRE's general partner, on a quarterly basis, for the allocable expenses the Partnership incurs in its performance under the Services Agreement. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for QRE or on QRE's behalf and expenses allocated by the Partnership to its affiliates. Such reimbursement of allocable expenses will be recognized as a reduction of operating expenses.

Income Taxes

We are treated as a partnership for income tax purposes. Generally, all of our taxable income and losses are reported on the income tax returns of the partners, and therefore, no provision for federal income taxes has been recorded in our accompanying consolidated financial statements. We are subject to Texas margin tax; however, such amounts are not significant.

Fair Value Measurements

The Partnership's 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. The Partnership's 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). 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.

As required by the statement, the Partnership utilizes 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.

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.

Business Combinations

The Partnership 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 Partnership 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 Partnership pays an affiliated entity to provide management services for the operation and supervision of its limited partnerships.

Equity Investments

The Partnership has an investment in an unconsolidated entity in which the Partnership does not own a majority interest but does have significant influence over, and is accounted for under the equity method. The Partnerships also accounts for its investment in QRE, a limited partnership formed by affiliates of the Partnership, under the equity method of accounting. The Partnership has a limited partnership ownership interest in QRE in excess of 50%, but does not have any ownership of the general partner of QRE or participating rights allowing the Partnership to participate in certain financial and operating decisions of QRE that are made in the ordinary course of business. Under the equity method of accounting, the Partnership's share of net income (loss) from its equity investment is reflected as an increase (decrease) in its investment account in "Other noncurrent assets" and is also recorded as "Equity in (losses) earnings" in "Other income (expenses)." Distributions from the equity investment are recorded as reductions of the Partnership's investment and contributions to the equity investment are recorded as increases of the Partnership's investment. The Partnership 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 4.

Employee Benefit Plan

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

Valuation-based compensation

The Partnership 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.

Recent Accounting Pronouncements

In February 2010, the FASB issued ASU 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements, which amends ASC 855 to address certain implementation issues related to an entity's requirement to perform and disclose subsequent-events procedures. All of the amendments in the Update are effective upon issuance of the final Update, except for conduit debt obligors, which is effective for interim and annual periods ending after June 15, 2010. Adoption of this Update did not have a material impact on our financial statements.

In January 2010, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2010-06, Improving Disclosures about Fair Value Measurements, 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.

NOTE 3 - ACQUISITION AND DIVESTITURE OF ASSETS

Acquisition of Melrose Properties

On December 22, 2010, the Partnership completed an acquisition of certain oil and gas assets (Melrose Properties) from Melrose Energy Company for $62.3 million in cash. The assets are located in the Permian Basin. Total proved reserves of the acquired properties are estimated to be 6.6 Mmboe at December 22, 2010. The transaction was funded from cash contributions from limited partners and borrowings under the Partnership's credit facility. The purchase price is subject to a final closing statement.

The acquisition qualifies as a business acquisition, and as such, the Partnership estimated the fair value of these properties as of the closing 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 Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 8.

The Partnership estimates the fair value of net assets acquired for the Melrose Properties to be approximately $66.8 million, which the Partnership considers to be representative of the price paid by a typical market participant. This measurement resulted in a bargain purchase of approximately $4.5 million, recorded as a reduction of operating expenses during the year ended December 31, 2010, and was primarily due to the increase in commodity prices as of the closing date of the acquisition versus the commodity prices at the effective date. The acquisition related costs related to the Melrose Properties acquisition were approximately $0.2 million and are recorded as acquisition evaluation costs for the year ended December 31, 2010.

The following table summarizes the consideration paid for the net assets acquired for the Melrose Properties and the preliminary fair value of the assets acquired and liabilities assumed as of December 22, 2010.

Consideration given to Melrose Resources
Cash	$	62,324

Recognized amounts of identifiable assets acquired and liabilities assumed:
Inventory of hydrocarbons	$	445
Proved developed properties		43,500
Proved undeveloped properties		31,900
Unproved properties		1,300
Environmental liability and claims of unratified mineral workers		(5,229	)
Asset retirement obligations		(5,100	)
Bargain purchase gain		(4,492	)
Total identifiable net assets	$	62,324

Acquisition of Denbury Properties

On May 14, 2010, the Partnership 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 acquisition, and as such, the Partnership 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 Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 8.

The Partnership 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 Partnership considered to be representative of the price paid by a typical market participant. This measurement resulted in neither goodwill nor a bargain purchase gain. The acquisition related costs related to the Denbury acquisition were approximately $1.2 million and are recorded as acquisition evaluation costs for 2010.

The following table summarizes the consideration paid for the net assets acquired for Denbury and the final fair value of the assets acquired and liabilities assumed as of May 14, 2010.

Consideration given to Denbury Resources, Inc.
Cash	$	888,785
Preferential rights		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		788,829
Proved undeveloped properties		84,000
Unproved properties		43,000
Suspended revenues payable		(4,521	)
Asset retirement obligations		(24,849	)
Total identifiable net assets	$	892,843

Acquisition of Jay Field Properties

On March 31, 2010, the Partnership signed and closed a purchase agreement to acquire land within the Jay field from International Paper Company for $3.1 million in cash.

Acquisition of Shongaloo Properties

On January 28, 2009, the Partnership 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 Partnership estimates the fair value of the net assets acquired for the Shongaloo Properties to be approximately $49.9 million, which the Partnership considers to be representative of the price paid by a typical market participant. This measurement resulted in a bargain purchase of approximately $1.2 million recorded as a reduction of operating expenses during the year ended December 31, 2009 and was primarily due to the increase in commodity prices as of the closing date of the acquisition versus the commodity prices at the effective date. The acquisition related costs related to the Shongaloo Properties acquisition were approximately $0.6 million and are recorded as acquisition evaluation costs for the year ended December 31, 2009.

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	$	51,600
Asset retirement obligations		(1,700	)
Bargain Purchase		(1,200	)
Total identifiable net assets	$	48,700

Divestiture of Non-core Assets

The Partnership divested through an auction process certain non-core oil and gas properties in Alabama, Colorado, Louisiana, New Mexico, and Texas representing approximately 8% of total production. The auction took place on August 12, 2009 and had an effective date of August 1, 2009 for sold non-operated properties and September 1, 2009 for sold operated properties. The Partnership received $16.3 million for these properties. The proceeds from the 2009 sales of oil and gas properties were recorded as reductions to capitalized costs pursuant to full cost accounting rules, and the cash received was used to reduce borrowings under a credit facility.

NOTE 4 - INVESTMENTS

The Partnership's equity investments consist of the following:

	December 31,
	2010		2009
Investment in QR Energy, LP	$	108,859	$	-
Investment in Ute Energy, LLC		49,503		41,597
	$	158,362	$	41,597

The Partnership's equity in earnings consists of the following:

	2010			2009
Equity in loss of QR Energy, LP	$	(3,911	)	$	-
Equity in earnings of Ute Energy, LLC		3,842			2,675
	$	(69	)	$	2,675

Investment in QR Energy, LP

On December 22, 2010, the Partnership acquired an interest in QRE in connection with the conveyance to QRE of certain assets with a net book value of $223.7 million. The net assets conveyed to QRE consist of the following:

Oil and gas properties, net	$	444,671
Derivative instrument liability, net		(1,425	)
Natural gas imbalance		(1,247	)
Asset retirement obligations		(18,263	)
Long-term debt		(200,000	)
	$	223,736

QR Energy, LP (QRE) is a Delaware limited partnership formed in September 2010 by affiliates of the Partnership to own and exploit producing oil and natural gas properties. QRE is engaged in the acquisition, exploitation, development and production of oil and natural gas properties and its business activities are conducted through QRE Operating LLC (OLLC), its wholly owned subsidiary. The MLP Fund contributed the net assets noted in the table above to QRE in connection with QRE's IPO on December 22, 2010. The conveyance of such assets was accounted for as a transaction between entities under common control at the historical net book values.

In connection with QRE's IPO, the MLP Fund contributed to QRE certain fields in the Permian Basin and the ArkLa-Tex, Mid-Continent and Gulf Coast areas and an overriding royalty interest in the Gulf Coast area in exchange for 11,297,737 common units and 7,145,866 subordinated units. In exchange, the MLP Fund received a cash distribution of $300.0 million from the net proceeds from the IPO and QRE assumed $200.0 million of the MLP Fund's debt.

At December 31, 2010, the MLP Fund owned 11,297,737 common units or approximately 43.0% of QRE's outstanding common units of 26,297,737, and 100% of QRE's 7,145,866 outstanding subordinated units, which resulted in an overall ownership percentage of 55.1% of QRE's outstanding units of 33,479,332. QRE's general partner owns 35,729 general partner units and is deemed to have control of QRE. The MLP Fund is also entitled to a management incentive fee, provided QRE Energy, LP meets certain distribution levels during any given quarter. The management incentive fee and general partner units are owned by the general partner.

The following table summarizes the excess consideration received over net assets conveyed as of December 22, 2010.

Cash received from QRE	$	300,000
Equity investment in QRE		112,669
Net assets conveyed at book value		(223,736	)
Excess consideration over contribution of net assets to affiliated company	$	188,933

The Partnership's equity in losses of QRE was $3.9 million for the year ended December 31, 2010. The Partnership's unconsolidated investment in QRE was $108.9 million as of December 31, 2010.

No impairment relating to the carrying value of its investment in QRE was recorded as of December 31, 2010.

A summarized balance sheet for QRE as of December 31, 2010 and a summarized statement of operations for the year ended December 31, 2010 are as follows:

QR Energy, LP

Summarized Balance Sheet

	December 31,
	2010
Current assets	$	16,215
Property and equipment, net		443,797
Other assets		12,006
Total assets	$	472,018

Current liabilities	$	13,141
Long-term debt		225,000
Other long-term liabilities		36,272
Owners' equity		197,605
Total liabilities and owners' equity	$	472,018

QR Energy, LP

Summarized Statement of Operations

	Period from
	December 22,
	2010 to
	December 31,
	2010
Revenues	$	3,014
Operating expenses		2,157
Operating profit		857
Interest expense		(304	)
Other expense		(7,652	)
Net loss	$	(7,099	)

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 Partnership initially acquired an interest in Ute and accounts for the investment using the equity method of accounting.

During 2008, the Partnership recorded an other-than-temporary impairment of $2.6 million in the carrying value of its investment. There were no impairments during the period from January 1, 2010 to December 21, 2010 or during 2009.

During 2008 and 2009, the Partnership 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 Partnership 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 $4.1 million. The non-cash recapitalization converted certain of the redeemable units into Class A common units at a valuation of $10 per unit, with the remaining 175,126 redeemable units that will accrue a return equal to 12% per annum, being retained by the Partnership. The overall recapitalization resulted in a decrease in the Partnership's common unit class ownership from 25% to 23.8%. As of December 31, 2010, the Partnership's ownership of Ute remains at 23.8%

The Partnership's equity in earnings of Ute was $3.8 million and $2.7 million for the years ended December 31, 2010 and December 31, 2009. The Partnership's unconsolidated investment in Ute was $49.5 million and $41.6 million as of December 31, 2010 and 2009.

The following table shows summarized financial information of the Partnership's investment in Ute for the years indicated:

Ute Energy, LLC

Summarized Balance Sheets

	December 31,
	2010		2009
Current assets	$	16,812	$	2,288
Property and equipment, net		86,620		34,417
Equity method investments		92,217		94,248
Other assets		1,392		1,978
Total assets	$	197,041	$	132,931

Current liabilities	$	18,708	$	5,538
Long-term liabilities		26,290		52,010
Members' equity		152,043		75,383
Total liabilities and members' equity	$	197,041	$	132,931

Ute Energy, LLC

Summarized Statements of Operations

	2010			2009
Revenues	$	38,883		$	10,025
Operating expenses		(27,834	)		(14,059	)
Operating profit (loss)		11,049			(4,034	)
Interest expense		(2,254	)		(2,275	)
Other income/(expense)		7,365			4,999
Net income (loss)	$	16,160		$	(1,310	)

Investment in Marketable Equity Securities

In 2008, the Partnership purchased $15.3 million of marketable equity securities. During the nine months ended September 30, 2009, the Partnership sold the remaining $11.5 million of the securities and recorded realized losses of $5.2 million, resulting in a change in the unrealized gain (loss) of $5.6 million. For the period since the original purchase, these securities have a cumulative $7.2 million realized loss. At December 31, 2010, and December 31, 2009, the Partnership did not own any marketable equity securities.

NOTE 5 — OTHER ASSETS

Other assets comprised the following as of the balance sheet dates indicated:

	December 31,
	2010		2009
Property reclamation deposit (see Note 16)	$	10,730	$	10,729
Inventories		7,533		5,496
Deferred financing costs, net of amortization		6,889		925
Other long-term assets		1,583		1,539
Other assets	$	26,735	$	18,689

NOTE 6 — ACCRUED AND OTHER LIABILITIES

Accrued and other liabilities comprised the following as of the balance sheet dates indicated:

	December 31,
	2010		2009
Accrued payables	$	29,442	$	8.572
Distributions payable (1)		20,686		-
Accrued property tax		3,923		2.047
Accrued bonuses		3,380		977
Accrued production and taxpayable		3,352		1,055
Other		3,591		1,107
	$	64,374	$	13,758

(1)

In connection with the conveyance of certain net assets to QRE, the Partnership paid a cash distribution of $300 million, of which a declared and irrevocable portion remained unpaid as of December 31, 2010. This portion was paid January 2011.

NOTE 7 — LONG-TERM DEBT

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

	December 31,
	2010		2009
Long-term debt:
Quantum Resources A1, LP	$	353,441	$	79,838
QRFC, LP		11,308		2,939
Black Diamond Resources, LLC		15,332		3,673
Total long-team debt	$	380,081	$	86,450

Irrevocable stand-by letters of credit:
Letters of credit outstanding under credit agreements	$	17,962	$	14,265

In September 2006, the Partnership, through its subsidiaries QRA1, QRFC, and Black Diamond entered into three separate five-year revolving credit agreements with a syndicated bank group (the Original Credit Facilities). The combined Original Credit Facilities have a maximum commitment of $840.0 million and a current conforming borrowing base of $127.8 million at December 31, 2009.

The Original Credit Facilities for QRA1 and Black Diamond are held by mortgages on their oil and gas properties and related assets. QRFC's credit facility is held by the oil and gas properties owned by QAC.

Borrowings under the Original Credit Facilities bear interest at the Alternative Base Rate (ABR) or the Eurodollar Rate plus a margin based on the borrowing base utilization. The margin ranges between 2% and 3% for Eurodollar loans and 1% and 2% for ABR loans. 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 14, 2010 the Partnership terminated its Original Credit Facilities and, through three of its subsidiaries, entered into three separate four-year revolving credit agreements (the New Credit Facilities) with a maturity date of May 14, 2014. All outstanding loans under the Original Credit Facilities 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. In conjunction with the amendments, the Partnership incurred $11.5 million of debt issuance costs which were capitalized and are being amortized over the term of the agreements. As of December 31, 2010, the Partnership's conforming borrowing base is $415 million.

Borrowings under the New Credit Facilities bear interest at the Alternative Base Rate (ABR) or the Eurodollar Rate plus a margin based on the borrowing base utilization. The margin ranges between 2% and 3% for Eurodollar loans and 1% and 2% for ABR loans. 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.

The new credit agreements require the Partnership 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 Partnership's ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and require delivery of audited financial statements within 120 days of the end of each fiscal year and reviewed quarterly financial statements within 45 days of the end of each quarter. The credit agreements also provide limits on the amount of commodity derivative contracts the Partnership may enter into, in particular prohibiting the Partnership 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 Partnership fails to perform its obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the credit agreements, together with accrued interest, could be declared immediately due and payable. As of December 31, 2010, the Partnership was in compliance with all financial covenants in its credit agreements, however, the Partnership 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.

As of December 31, 2010, the credit agreements had $18.0 million in outstanding letters of credit primarily related to the Jay Field abandonment and insurance requirements. In connection with the Partnership's Jay Field abandonment and remediation obligations (see Note 16), the Partnership is required to provide $3.0 million letter of credit each year through 2012. The letters of credit issued to pursuant to this obligation are $15.0 million and $12.0 million as of December 31, 2010 and December 31, 2009.

The weighted average interest rate was 4.6% on outstanding advances of $380.1 million. As of December 31, 2010, the Partnership had availability under the credit agreements of $16.9 million.

NOTE 8 - FAIR VALUE MEASUREMENTS

The following table sets forth, by level within the hierarchy, the fair value of the Partnership's financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010 and December 31, 2009.

	Total			Level 1		Level 2			Level 3
December 31, 2010
Assets:
Commodity derivatives	$	29,120		$	-	$	29,120		$	-
Interest rate derivatives		8,100			-		8,100			-
Liabilities:
Commodity derivatives	$	(91,088	)	$	-	$	(91,088	)	$	-
Interest rate derivatives		(10,470	)		-		(10,470	)		-

	Total			Level 1		Level 2		Level 3
December 31, 2009
Assets:
Commodity derivatives	$	7,783		$	-	$	-	$	7,783
Liabilities :
Commodity derivatives	$	(67,482	)	$	-	$	-	$	(67,482	)

All fair values reflected in the table above and on the consolidated balance sheets have been adjusted for nonperformance risk. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 1 - Fair Value Measurements

As of December 31, 2010 and December 31, 2009, the Partnership did not have assets or liabilities measured under a Level 1 fair value hierarchy.

Level 2 - Fair Value Measurements

As discussed below, the Partnership transferred all derivative instruments which are measured on a recurring basis from Level 3 into Level 2.

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.

Level 3 - Fair Value Measurements

As of December 31, 2010, the Partnership did not have assets or liabilities measured under a Level 3 fair value hierarchy.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2010 and 2009 and the reclassification of all derivative instruments from Level 3 into Level 2:

	2010			2009
Balance at beginning of year	$	(59,699	)	$	-
Total gains or losses (realized or unrealized):
Included in other income (expense)		25,563			(63,530	)
Included in other comprehensive income		(2,325	)		-
Purchases, issuances and settlements		-			(45,853	)
Transfers in and out of Level 3		36,461			49,684
Balance at end of year	$	-		$	(59,699	)

Changes in unrealized gains (losses) relating to derivatives still held as of December 31, 2010	$	-		$	(111,113	)

On December 22, 2010, the Partnership novated certain derivative instruments to QRE. We accounted for these derivative instruments at fair value of which there was a $1.4 million net liability position. These derivative instruments are classified as Level 2 fair value measurements.

The following table summarizes the derivative instruments conveyed to QRE as of December 22, 2010:

Derivative assets	$	19,646
Derivative liabilities		(21,071	)
	$	(1,425	)

As part of a broad review by management of the Partnership's financial statement disclosures, management has determined, effective October 1, 2010, the fair values of the derivative instruments of the Partnership should be classified as Level 2. As part of management's review, a third-party valuation specialist used to value the Partnership'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 Partnership transferred all derivative instruments which are measured on a recurring basis from Level 3 into Level 2.

As part of the acquisition of the Melrose, Denbury and Shongaloo properties described in Note 3, the Partnership performed nonrecurring fair value measurements on the assets acquired. These measurements are classified as Level 3 fair value measurements.

NOTE 9 - DERIVATIVES

The following tables reflect the amounts that were recorded as derivative assets and liabilities on our Consolidated Balance Sheet at December 31. 2010 and 2009:

	2010				2009
	Asset Derivatives		Liability Derivatives		Asset Derivatives		Liability Derivatives
Derivative not designated as hedging instruments:
Comrmdity instruments	$	29,120	$	91,088	$	7,783	$	67,482
Interest Rate Instruments		8,100		10,470		-		-
Total derivatives not designated as hedging instruments	$	37,220	$	101,558	$	7,783	$	67.482

Oil and Gas Commodity Hedges

As of December 31, 2010, the notional volumes of the Partnership commodity hedges were:

Commodity	Index	2011			2012			2013			2014			2015
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		3,783			3,055			2,915			1,021			340
Average price ($/Bbls)		$	71.83		$	71.78		$	69.61		$	73.93		$	84.50
Collars
Hedged Volume (Bbls/d)	WTI		700			741			33			1,533			2,000
Average floor price
($/Bb1s)		$	70.00		$	69.45		$	60.00		$	69.79		$	70.00
Average ceiling price
($/Bbls)		$	110.00		$	108.00		$	78.20		$	105.99		$	110.00
Natural gas positions:
Swaps
Hedged Volume
(MMBtu/d)	NYMEX		33,881			26,319			23,616			18,662			2,977
Average price
($/MMBtu)		$	5.22		$	5.64		$	5.92		$	6.18		$	5.48
Basis Swaps
Hedged Volume
(MMBtu/d)	NYMEX		2,959			2,623			2,466			2.466			-
Average price
($/MMBtu) (1)		$	(0.16	)	$	(0.16	)	$	(0.15	)	$	(0.15	)	$	-
Collars
Hedged Volume	Henry
(MMBtu/d)	Hub		-			2,623			2,466			2,466			-
Average floor price
($/MMBtu)		$	-		$	6.50		$	6.50		$	6.50		$	-
Average ceiling price
($/MMBtu)		$	-		$	8.60		$	8.65		$	8.85		$	-

(1)

Our basis swaps effectively limit our exposure to differences between the NYMEX gas price and the price at the location where we sell our gas. The average prices listed above are the amounts we will pay per MMBtu relative to the NYMEX price to "lock-in" these locational price differences.

The Partnership has elected not to designate the oil and gas commodity hedges as cash flow hedges. 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 table below summarizes the realized and unrealized gains and fosses the Partnership incurred related to its oil and natural gas derivative instruments for the year ended December 31, 2010 and 2009.

	2010			2009
Realized gains on commodity derivatives	$	5,373		$	47,993
Unrealized losses on commodity derivatives		(3,694	)		(111,113	)
Gain (loss) on commodity derivative contracts (1)	$	1,679		$	(63,120	)

(1)Included in other income (expense) in the consolidated statement of operations.

Interest Rate Derivative Contracts

During October 2007, the Partnership entered into a derivative instrument for a notional amount of $100.0 million to effectively fix the LIBOR component of the interest rate on its credit facility during the period from October 31, 2007 to October 31, 2009. Under the derivative instrument, the Partnership made payments to (or received payments from) the contract counterparty when the variable interest rate of the one-month LIBOR fell below or exceeded the fixed rate of 4.29%.

During June 2010, the Partnership 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 Partnership will make payments to (or receive payments from) the contract counterparties when the variable interest rate of the one-month LIBOR falls below or exceeds the fixed rate of 2.74% during the period from June 2010 to December 2016. In addition, the Partnership will make (or receive) payments from the contract counterparties when the one-month LIBOR falls below or exceeds the fixed rate of 1.95% during the period from July 2010 to December 2016 under the second tranche.

The table below summarizes the realized and unrealized gains and losses the Partnership incurred related to its interest rate derivative instrument for the years ended December 31, 2010 and 2009.

	2010			2009
Realized losses on interest rate swaps	$	(5,052	)	$	(3,299	)
Unrealized (losses) gains on interest rate swaps		(2,371	)		2,949
Losses on interest rate swaps (1)	$	(7,423	)	$	(350	)

(1) Included in interest expense in the consolidated statement of operations.

NOTE 10 - ASSET RETIREMENT OBLIGATIONS

The Partnership has a total of approximately $51.5 million as of December 31, 2010 for future asset retirement obligations in connection with its oil and gas properties. The following is a summary of the Partnership's asset retirement obligations as of and for the years ended December 31, 2009 and 2010.

	2010			2009
Beginning of the year	$	35,244		$	42,094
Assumed in acquisitions		29,937			1,732
Divested properties		(18,263	)		(6,226	)
Revisions to previous estimates		-			1,723
Liabilities incurred		1,714			636
Liabilities settled		(967	)		(8,300	)
Accretion expense		3,786			3,585
End of the year		51,451			35,244
Less: Current portion of asset retirement obligations		2,318			2,250
Asset retirement obligations - non-current	$	49,133		$	32,994

NOTE 11 - PARTNERS' CAPITAL

QA Global is the general partner of, and owns a 1% interest in QAH. The limited partners of QAH are QR Aspect Asset Management and members of management of QAH and own a 99% interest in QAH. The earnings of the Partnership are allocated to the partners based on their respective ownership percentages.

The LP's have received subscriptions for limited partnership interests from their limited partners totaling approximately $1.2 billion as of December 31, 2010. QAP, the general partner of the LP's, has made an equity commitment of $36.1 million, which represents 3% of the total equity commitments received. The limited partnership agreements with the LPs provide that QAP can request funding of equity commitments with a minimum 10 business days notice. As of December 31, 2010, QAP and the LP's had funded $1.1 billion of their equity commitments. For the years ended December 31, 2010 and 2009, there were distributions paid to QAP and the LP's of $330.0 million and $27.2 million.

The LP's pay management fees to QAAM as specified in the respective partnership agreements. QAP receives, after the limited partners have recovered their initial investment and a preferred rate of return, participation in an additional 14% of cash flows generated by the LP's.

The LP's limited partnership agreements provide that they will pay organization costs and costs paid to third parties for services in connection with obtaining funding commitments from the limited partners (placement agent fees). The LP's combined are responsible for organization costs up to a limit of $1.5 million. Any costs in excess of this amount are paid by the partnerships; however, the management fees paid to QAAM are reduced by a corresponding amount.

NOTE 12 - SHARE-BASED COMPENSATION

Partnership's Long-Term Incentive Compensation Plan

In April 2009, the Partnership 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 Partnership through its subsidiaries. During the year ended December 31, 2010 the Partnership 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 Partnership or its subsidiaries as follows:

The Partnership General Partnership (Funded) Interest

The Partnership 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 Partnership 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 Partnership 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 Partnership 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 years ended December 31, 2010 and December 31, 2009. The Partnership incurred non-cash compensation expense related to the GP Funded Interest awards of $0.2 million and $0.1 million for the years ended December 31, 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 31, 2010.

Activity related to the GP Funded Interests is as follows:
	% of Interest Granted			Weighted Average Grant Date Fair Value Per 1%
Nonvested GP Funded Interests as of December 31, 2008		0.00	%	$	-
Granted		72.82	%		57,512
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 31, 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 31, 2010					83.95	%

The Partnership General Partner Promote Interest

After all investors in the Fund have received a return of their equity contributions plus a return of 8%, the Partnership 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 Partnership 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 Partnership 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 years ended, December 31, 2010 and December 31, 2009. The Partnership incurred non cash compensation expense of $0.2 million and $0.1 million for the years ended December 31, 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 31, 2010.

Activity related to the GP Promote Interests is as follows:
	% of Interest Granted			Weighted Average Grant Date Fair Value Per 1%
Nonvested OP Promote Interests as of December 31,2008		0.00	%	$	-
Granted		78.83	%		71,534
Forfeited		0.00	%		-
Nonvested (P 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 31, 2010		96.28	%	$	169,078

Activity related to the GP Promote Interests is as follows:

Nonvested CP 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 CP Promote Interests as of December 31, 2010					85.36	%

Purchase/Carry Interests

The Partnership, 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 Partnership 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 Partnership 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 Partnership incurred non-cash compensation expense of $0.6 million and $0.4 million for the years ended December 31, 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 31, 2010.

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

Activity related to the Purchase/Cary Interests is as follows:

Nonvested Purchase/Carry Interests as of December 31, 2008					0.00	%
Granted					100.00	%
Vested					0.00	%
Forfeited					0.00	%
Nonvested Purchase/Carry Interests as of December 31, 2009					100.00	%
Granted					0.00	%
Vested					-7.50	%
Forfeited					0.00	%
Nonvested Purchase/Carry Interests as of December 31, 2010					92.50	%

Performance Cash Deferred Compensation Plan

In April 2009, the Partnership 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 Partnership 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 31, 2010. These awards are liability-classified awards as they will ultimately settle in cash.

Out of Period Adjustment

During 2010 the Partnership recorded an adjustment 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 Partnership concluded its previously issued financial statements were not materially misstated and the effect of recognizing this adjustment in the 2010 financial statements were not material to the 2010 results of operations, financial position and cash flows.

NOTE 13 - NATURAL GAS IMBALANCES

We account for our natural gas imbalances under the sales method. We had over-produced liabilities of $5.0 million included in accrued liabilities on our consolidated balance sheet as of December 31, 2010 for over-produced positions which were beyond ultimate recoverability of remaining natural gas reserves.

As of December 31, 2010, our gross under-produced natural gas position was approximately $4.2 million (1,038 MMcf) and our gross over-produced natural gas position was approximately $6.6 million (1,645 MMcf). These gross positions were valued at $4.00 per Mcf without regard to remaining natural gas reserves.

As of December 31, 2009, the Partnership had over-produced liabilities of $0.8 million of natural gas imbalance positions.

NOTE 14 - EMPLOYEE BENEFIT PLANS

The Partnership has a 401(k) savings plan available to all eligible employees. For the year ended December 31, 2010, the Partnership matched 100% of employee contributions up to 3% of the employee's salary, whereas for the year ended December 31, 2009, the Partnership matched 100% of employee contributions up to 6% of the employee's salary. Matching contributions vest immediately. The Partnership made matching cash contributions to the plan for the years ended December 31, 2010 and 2009 of approximately $0.4 million and $0.6 million.

NOTE 15 - RELATED-PARTY TRANSACTIONS

Affiliate Management Agreement

The LP's have management agreements with QAAM, an affiliated entity, to provide management services for the operation and supervision of the partnerships. The management fee is determined by a formula based on the partners' invested capital or the equity capital commitment. During the years ended December 31, 2010 and 2009, the partnerships paid $10.8 million and $12.0 million, to QAAM for management fees.

Agreements with QRE

In connection with the MLP Fund's conveyance of certain assets to QRE, the Partnership entered into several agreements. The following is a description of those agreements.

Contribution Agreement

On December 22, 2010, in connection with the closing of QRE's IPO, the MLP Fund entered into a Contribution Agreement by and among the MLP Fund and QRE and its general partner and affiliates. Pursuant to the Contribution Agreement, the MLP Fund contributed net assets of $223.7 million to QRE in exchange for 11,297,737 common and 7,145,866 subordinated limited partner units and a $300 million cash distribution.

Services Agreement

Pursuant to the Services Agreement between the Partnership and QRE, the Partnership provides administrative and acquisition advisory services necessary to allow QRE's general partner to manage, operate and grow QRE's business. QRE does not have any employees. The Services Agreement requires that employees of the Partnership (including the persons who are executive officers of QRE's general partner) devote such portion of their time as may be reasonable and necessary for the operation of QRE's business. The executive officers of QRE's general partner currently devote a majority of their time to QRE's business, and are expected to continue to do so for the foreseeable future.

The following table summarizes transactions under the Services Agreement between the Partnership and QRE during the period from December 22, 2010 to December 31, 2010:

Ad valorem taxes paid by the Partnership on QRE's behalf	$	22
Interest paid by the Partnership on QRE's behalf		263
Debt issue costs paid by the Partnership on QRE's behalf		102
Intercompany financing to QRE		387
Administrative services fee due from QRE		55
Net increase in affiliate receivable	$	442

General and administrative expense applicable to QRE (1)	$	184

(1) Represents general and administrative expenses borne by the Partnership, but will not be paid by QRE to the Partnership.

Omnibus Agreement

On December 22, 2010, in connection with the closing of QRE's IPO, the Partnership also entered into an Omnibus Agreement (the "Omnibus Agreement") by and among it, QRE GP, OLLC, the MLP Fund and QA Global.

Under the terms of the Omnibus Agreement, the MLP Fund will offer QRE 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 MLP Fund. Additionally, the MLP Fund will allow QRE to participate in acquisition opportunities to the extent that it invests any of the remaining approximately $150 million of its unfunded committed equity capital. Specifically, the MLP Fund will offer QRE 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 MLP 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 QRE 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 MLP Fund will indemnify QRE 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 QRE's IPO. The MLP Fund indemnification obligation will (i) survive for one year after the closing of QRE's IPO with respect to title, and (ii) terminate upon the expiration of the applicable statute of limitations with respect to income taxes. QRE will indemnify the MLP Fund against certain potential environmental claims, losses and expenses associated with the operation of QRE's business that arise after the consummation of QRE's IPO.

Other Affiliate Transactions

In addition to the affiliate transactions with QRE described above, QAH has advanced funds to affiliated entities primarily for management fees paid on behalf of affiliates during 2010. The following table summarizes the related party receivables as of December 31, 2010:

	December 31, 2010
QA Asset Management LP	$	3,159
QRE Operating LLC		441
QA Global GP LW		10
	$	3,610

NOTE 16 - COMMITMENTS AND CONTINGENCIES

Property Reclamation Deposit

In connection with the 2006 Gulf Coast acquisition between ExxonMobil Corporation and QRM, the Partnership was required to deposit $10.0 million into an escrow account as security for abandonment and remediation obligations. As of December 31, 2010 and December 31, 2009, $10.7 million was recorded in other assets related to the deposit. In addition to the cash deposit, the Partnership was required to provide a $3.0 million letter of credit. The agreement requires an additional $3.0 million letter of credit to be issued in favor of the seller each year through 2012. Letters of credit totaling $15.0 million and $12.0 million had been issued as of December 31, 2010 and December 31, 2009. The Partnership is required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to the Partnership until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, the Company has the right to request a refund of a portion or all of the property reclamation deposit. Granting of the request is at the seller's sole discretion.

Operating Lease Commitments

At December 31, 2010, the Partnership had long-term leases extending through 2015 covering office space and equipment. The Partnership's future minimum rental payments under these leases as of December 31, 2010 are as follows:

Years Ending December 31,	Amount
2011	$	936
2012		896
2013		29
2014		27
2015		3

Approximately 92% of the Partnerships 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 4 month rent holiday to be taken from the commencement date. Total rental expense incurred for the years ended December 31, 2010 and 2009 was approximately $0.9 million and $3.0 million

Capital Lease Commitments

At December 31, 2010, the Partnership has a long-term capital lease extending through 2012 covering office furniture and equipment. The Partnership's future minimum rental payments under this lease as of December 31, 2010 are as follows:

Years Ending December 31,	Amount
2011	$	51
2012		51
Total minimum lease payments	$	102
Less: Amount representing interest		1
Present value of net minimum lease payments	$	101

Legal Proceedings

The Partnership is involved in various suits and claims arising in the normal course of business. The Partnership related entities owning record working interest in the Jay Field, brought suit against Santa Rosa County, Florida, protesting the County's assessed value for the Jay interests for calendar years 2009 and 2010. Santa Rosa County assessed the value of the Jay Field at approximately $92.0 million for each year. The Partnership made good faith payments for each calendar year based on valuations of $5.0 million and $45.0 million. If the County were to prevail in its assessed value, the resulting additional tax to the Partnership will be approximately $1.3 million for 2009 and $0.8 million for 2010. The Partnership believes it has a sound case to prevail on an assessed value lower than that asserted by Santa Rosa County for each calendar year.

In April 2011, the Partnership 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 initial evaluation, the Partnership believes there is no evidence to support a material liability.

In management's opinion, the ultimate outcome of these items will not have a material adverse effect on the Partnership's consolidated results of operations, financial position or cash flows. Based on management's assessment, no contingent liabilities have been recorded as of December 31, 2010 and 2009.

NOTE 17 - SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2010		2009
Cash:
Cash paid for state income tax	$	108	$	182
Cash paid during the period for interest		12,600		2,480
Noncash:
Change in accrued capital expenditures	$	10,100	$	(11,206	)
Insurance premium financed		2,075		1,695
Net additions (reductions) to asset retirement obligations		12,421		(10,435	)
Net assets contributed to QRE	223,736			-

NOTE 18 - SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have evaluated events that have occurred after December 31, 2010 through June 7. 2011. The following are subsequent events:

The Credit Agreement requires the Partnership to deliver audited financial statements within 120 days after year-end and reviewed quarterly financial statements within 45 days after quarter-end. We did not provide our audited financial statements by April 30, 2011 for which we sought and received a waiver to extend this reporting requirement by 45 days.

On February 28, 2011, the Partnership novated the following LIBOR-based interest rate swaps with a fair value of $2.9 million net asset position to QRE:

	Weighted Average
	Fixed LIBOR	Notional
Period	Rate	Amount
2011	1.88%	$225 million
2012	1.88%	$225 million
2013	1.87%	$225 million
2014	1.87%	$225 million
2015	1.87%	$225 million

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Capitalized Costs

The following tables set forth the capitalized costs related to our oil and natural gas producing activities as of December 31, 2010 and 2009.

	December 31,
	2010			2009
Proved oil and natural gas properties	$	998,901		$	709,552
Unproved oil and natural gas properties		40,000			-
		1,038,901			709,552
Accumulated depreciation, depletion and amortization		(371,023	)		(589,694	)
Net capitalized costs	$	667,878		$	119,858

Pursuant to the FASB's authoritative guidance on asset retirement obligations, net capitalized costs include asset retirement costs $44.6 million and $29.6 million as of December 31, 2010 and 2009.

Costs Incurred

Our oil and natural gas activities are conducted in the United States. The following tables summarize the costs incurred by us for the years ended December 31, 2010 and 2009.

	2010		2009
Acquisition of oil and natural gas properties:
Proved	$	948,229	$	49,145
Unproved		44,300		-
Development costs		63,800		7,152
Total	$	1,056,329	$	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 Partnership adopted the rules effective December 31, 2009, and the rule changes, including those related to pricing and technology, are included in its reserve estimates.

Third Party Reserves Estimate. The reserve estimates as of December 31, 2010 and 2009 presented in the table below were based on reserve reports prepared by Miller & Lents, Ltd., independent reserve engineers, using FASB and SEC rules in effect as of December 31, 2010 and 2009.

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:

	Oil (MBbl)			Natural Gas (MMcf)			NGL (MBbl)
Proved reserves:
Balance, December 31, 2008		8,182			34,753			-
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 (1)		8,308			45,342			2,086
Purchases of reserves in place		28,207			245,378			2,592
Revisions of previous estimates		5,653			(1,050	)		244
Production		(2,230	)		(15,206	)		(291	)
Conveyance of reserves to QRE		(19,511	)		(57,700	)		(1,363	)
Balance, December 31, 2010 (2)		20,427			216,764			3,268
Proved developed reserves :
December 31, 2009		6,721			44,879			2,037
December 31, 2010		15,162			151,051			3,093

(1) These reserves include 7,740 MBbl, 42,235 MMcf and 1,943 MBbl of Oil, Natural Gas and NGLs attributable to an approximate 93.2% noncontrolling interest in the Partnership as of December 31, 2009.

(2) These reserves include 19,058 MBbl, 202,241 MMcf and 3,049 MBbl of Oil, Natural Gas and NGLs attributable to an approximate 93.3% noncontrolling interest in the Partnership as of December 31, 2010.

Purchases of Reserves in Place. The 30,799 MBbl of liquids and 245,378 MMcf of natural gas purchased in 2010, was associated with the Melrose and Denbury acquisitions. The 1,589 MBbl of liquids and 20,169 MMcf of natural gas purchased in 2009, was associated with the Shongaloo Properties acquisition.

Conveyance to QRE. In 2010, the Partnership conveyed certain fields in the Permian Basin and the Ark-La-Tex, Mid-Continent and Gulf Coast areas and an overriding royalty interest in the Gulf Coast area to its affiliate QRE.

Sale of Reserves in Place. In 2009, the Partnership 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 2010, the Partnership had net positive revisions of 5,897 MBbl of oil primarily due to higher commodity prices in 2010 as compared to 2009 and net negative revisions of 1,050 MMcf of natural gas primarily due to lower commodity prices in 2010 as compared to 2009. In 2009, the Partnership 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

Future oil and natural gas sales and production and development costs have been estimated in accordance with the Final Rule (see Note 2). 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 $79.43/Bbl for oil and $4.38/MMbtu for natural gas as of December 31, 2010; the unweighted arithmetic average first-day of-the-month prices for the prior 12 months were $61.18/Bb1 for oil and $3.87/MMbtu for natural gas as of December 31, 2009; and the index prices were $41.00/Bbl for oil and $5.71/MMbtu for natural gas as of December 31, 2008. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2010, the relevant average realized prices for oil, natural gas and NGLs were $76.48 per Bbl, $4.00 per Mcf and $46.43 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 the Partnership's reserves.

The estimated standardized measure of discounted future net cash flows relating to the Partnership's proved reserves is shown below:

	December 31,
	2010(1)			2009(2)
Future cash inflows	$	2,715,504		$	707,028
Future production and development costs		(1,302,795	)		(319,391	)
Future net cash flows		1,412,709			387,637
10% annual discount for estimated timing of cash flows		(691,684	)		(170,762	)
Standardized measure of discounted future net cash flows	$	721,025		$	216,875

(1) This standardized measure of discounted cash flows includes $672.7 million attributable to an approximate 93.3% noncontrolling interest in the Partnership as of December 31, 2010.

(2) This standardized measure of discounted cash flows includes $202.1 million attributable to an approximate 93.2% noncontrolling interest in the Partnership as of December 31, 2009.

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 years ended December 31, 2010 and 2009:

	December 31,
	2010			2009
Beginning of period	$	216,875		$	131,584
Purchases of reserves in place		925,184			51,202
Conveyance of reserves to QRE		(500,487	)		(10,106	)
Revisions of previous estimates		81,587			33,930
Changes in future development cost, net		2,250			3,149
Development cost incurred during the year that reduce future development costs		1,882			1,853
Net change in prices		38,709			51,552
Sales, net of production costs		(154,804	)		(23,724	)
Changes in timing and other		88,141			(35,723	)
Accretion of discount		21,688			13,158
End of period	$	721,025		$	216,875

Partnership's share of QRE Energy, LLP and Ute Energy, LLC

The Partnership has investments in QRE and UTE that are accounted for under the equity method. The following disclosures represent our share of QRE's and Ute's reserves and oil and gas operations as of December 31, 2010 and 2009.

Capitalized Costs

The following table summarizes the carrying value of our portion of QRE's and Ute's consolidated oil and gas assets as of December 31, 2010 and 2009.

	December 31,
	2010						2009
	QRE			Ute			QRE		Ute
Proved oil and natural gas properties	$	244,989		$	26,704		$	-	$	12,020
Unproved oil and natural gas properties		(503	)		(7,187	)		-		(3,705	)
		244,486			19,517			-		8,315
Accumulated depreciation, depletion and amortization		-			1,067			-		268
Net capitalized costs	$	244,486		$	20,584		$	-	$	8,583

Costs Incurred

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

	December 31,
	2010		2009
Acquisition of oil and natural gas properties:
Proved	$	812	$	2,787
Development costs		14,631		-
Asset retirement obligation		116		-
Total	$	15,559	$	2,787

Estimated Proved Reserves

All of QRE's and Ute's proved reserves are located entirely within the continental United Sates. Following is a summary of our share of the proved developed and total proved oil, natural gas and NGL reserves attributed to QRE's and Ute's operations.

	Oil (MBbl)						Natural Gas (MMcf)						NGL (MBbl)
Proved reserves:	QRE			Ute			QRE			Ute			QRE			Ute
Balance, December 31, 2008	-				227		-				900		-			-
Revisions of previous estimates	-				551			-			1,274		-			-
Production	-				(55	)		-			(193	)	-			-
Extensions, discoveries and other additions	-				280			-			660		-			-
Divestiture of reserves	-				-			-			(38	)		-			-
Balance, December 31, 2009	-				1,003			-			2,603			-			-
Revisions of previous estimates	-				(124	)		-			(205	)		-			-
Production		(14	)		(123	)		(78	)		(296	)		(2	)		-
Conveyance of reserves to QRE		10,749			-			31,787			-			751			-
Extensions, discoveries and other additions		-			1,117			-			2,552			-			-
Recapitalization		-			(140	)		-			(529	)		-			-
Balance, December 31, 2010		10,735			1,733			31,709			4,125			749			-

Proved developed reserves:
December 31, 2009		-			283			-			1,078			-			-
December 21, 2010		6,378			611			26,200			1,686			719			-

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.

For the year ended December 31, 2010, our share of QRE'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. Calculations were made using SEC prices of $79.43 per Bbl WTI index for oil and $4.376 per MMBtu NYMEX index for gas.

The estimated standardized measure of discounted future net cash flows relating to our share of QRE's and Ute's proved reserves is shown below:

	December 31,
	2010						2009
	QRE			Ute			QRE		Ute
Future cash inflows	$	976,364		$	132,914		$	-	$	57,291
Future production and development costs		(406,444	)		(87,560	)		-		(38,719	)
Future net cash flows		569,920			45,354			-		18,572
10% annual discount for estimated timing of cash flows		(295,347	)		(18,530	)		-		(9,625	)
Standardized measure of discounted future net cash flows	$	274,573		$	26,824		$	-	$	8,947

A summary of changes in the standardized measure of discounted future net cash flows is as follows:

	December 31,
	2010						2009
	QRE			Ute			QRE		Ute
Beginning of period	$	-		$	8,947		$	-	$	3,514
Sales of reserves in place		-			-			-		(65	)
Conveyance of reserves to QRE		275,716			-			-		-
Revisions of previous estimates		-			(964	)		-		2,374
Changes in future development cost, net		-			1,344			-		210
Development cost incurred during the year that reduce future development costs		-			1,779			-		106
Net change in prices		-			5,196			-		192
Sales, net of production costs		(1,143	)		(7,601	)		-		(1,340	)
Changes in timing and other		-			2,499			-		653
Accretion of discount		-			703			-		351
Recapitalization		-			(1,916	)		-		-
Extensions, discoveries and improved recoveries less related costs		-			16,837			-		2,952
End of period	$	274,573		$	26,824		$	-	$	8,947