QR Energy, LP - FORM 8-K - EX-99.1 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Attached files

file	filename
8-K - FORM 8-K - QR Energy, LP	d361696d8k.htm
EX-23.1 - CONSENT OF PRICEWATERHOUSECOOPERS, LLP - QR Energy, LP	d361696dex231.htm
EX-99.2 - FINANCIAL STATEMENTS - QR Energy, LP	d361696dex992.htm
EX-99.3 - REPORT OF MILLER AND LENTS, LTD. - QR Energy, LP	d361696dex993.htm
EX-23.3 - CONSENT OF MILLER AND LENTS, LTD. - REPORT DATED APRIL 10, 2012 - QR Energy, LP	d361696dex233.htm
EX-23.2 - CONSENT OF MILLER AND LENTS, LTD. - REPORT DATED FEBRUARY 15, 2012 - QR Energy, LP	d361696dex232.htm

EXHIBIT 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of QRE GP, LLC

and the Unitholders of QR Energy, LP

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

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

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

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 15, 2012, except for Note 18, as to which the date is June 1, 2012.

QR ENERGY, LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)


	December 31, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	17,433		$	2,195
Accounts receivable: oil and gas sales		32,263			3,014
Due from affiliate		3,734			—
Due from general partner		—			715
Derivative instruments		32,683			9,887
Prepaid and other current assets		249			1,283

Total current assets		86,362			17,094

Noncurrent assets:
Oil and gas properties, using the full cost method of accounting		975,182			892,649
Gas processing equipment		865			109
Less accumulated depreciation, depletion, amortization		(80,484	)		(2,130	)

Total property and equipment, net		895,563			890,628
Derivative instruments		70,570			26,415
Deferred taxes		290			1,100
Deferred financing costs, net of amortization		4,279			3,478

Total noncurrent assets		970,702			921,621

Total assets	$	1,057,064		$	938,715

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Due to affiliates	$	—		$	442
Current portion of asset retirement obligations		348			4,166
Derivative instruments		9,569			10,886
Accrued and other liabilities		50,027			8,021

Total current liabilities		59,944			23,515

Noncurrent liabilities:
Long-term debt		500,000			452,000
Derivative instruments		16,906			46,801
Asset retirement obligations		65,353			39,248
Deferred taxes		20			—

Total noncurrent liabilities		582,279			538,049

Commitments and contingencies (See Note 8)
Partners’ capital:
Predecessor’s capital		—			179,546
Class C converible preferred unitholders (16,666,667 and zero units issued and outstanding as of December 31, 2011 and 2010)		358,138			—
General partner (35,729 units issued and outstanding as of December 31, 2011 and 2010)		546			708
Public common unitholders (17,292,279 and 15,000,000 units issued and outstanding as of December 31, 2011 and 2010)		241,306			276,723
Affiliated common unitholders (11,297,737 units issued and outstanding as of December 31, 2011 and 2010)		(113,414	)		(48,898	)
Subordinated unitholders (7,145,866 units issued and outstanding as of December 31, 2011 and 2010)		(71,735	)		(30,928	)

Total partners’ capital		414,841			377,151

Total liabilities and partners’ capital	$	1,057,064		$	938,715

See accompanying notes to the consolidated financial statements

QR ENERGY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)


	Partnership						Predecessor
	Year Ended December 31, 2011			December 22 to December 31, 2010			January 1 to December 21, 2010			Year Ended December 31, 2009
Revenues:
Oil and natural gas sales	$	257,903		$	6,661		$	244,572		$	69,823
Processing and other		1,965			24			8,814			2,978

Total revenues		259,868			6,685			253,386			72,801

Operating Expenses:
Production expenses		88,057			2,355			108,408			44,841
Impairment of oil and gas properties		—			—			—			28,338
Depreciation, depletion and amortization		78,354			2,130			66,482			16,993
Accretion of asset retirement obligations		2,702			77			3,674			3,585
Management fees		—			—			10,486			12,018
Acquisition evaluation costs		—			—			1,192			582
Offering costs		—			—			5,148			—
General and administrative		31,666			763			25,477			18,697
Bargain purchase gain		—			—			—			(1,200	)
Other expense		—			—			224			—

Total operating expenses		200,779			5,325			221,091			123,854

Operating income (loss)		59,089			1,360			32,295			(51,053	)
Other income (expense):
Equity in earnings of Ute Energy, LLC (See Note 15)		—			—			3,782			2,675
Dividends on investment in marketable equity securities		—			—			—			233
Gain on investment in marketable equity securities		—			—			—			394
Realized (losses) gains on commodity derivative contracts		(72,053	)		(289	)		5,373			47,993
Unrealized gains (losses) on commodity derivative contracts		120,478			(12,068	)		8,204			(111,113	)
Gain on equity share issuance (See Note 15)		—			—			4,064			—
Interest expense, net		(45,527	)		(1,136	)		(22,179	)		(3,716	)
Other income (expense)		—			—			482			(645	)

Total other income (expense), net		2,898			(13,493	)		(274	)		(64,179	)

Income (loss) before income taxes		61,987			(12,133	)		32,021			(115,232	)
Income tax (expense) benefit, net		(850	)		66			(108	)		(182	)

Net income (loss)		61,137			(12,067	)		31,913			(115,414	)
Net income (loss) attributable to noncontrolling interest		—			—			30,101			(107,528	)

Net income (loss) attributable to controlling interest		61,137			(12,067	)	$	1,812		$	(7,886	)

Net (income) loss attributable to predecessor operations		(49,091	)		4,968
Distributions on Class C convertible preferred units		(7,062	)		—

Net income (loss) available to other unitholders		4,984			(7,099	)
Less: general partner’s interest in net income (loss)		1,575			(7	)
Limited partner’s interest in net income (loss)	$	3,409		$	(7,092	)

Common unitholders’ interest in net income (loss)	$	2,730		$	(5,577	)
Subordinated unitholders’ interest in net income (loss)	$	679		$	(1,515	)
Net income (loss) per limited partner unit:
Common unitholders’ (basic and diluted)	$	0.10		$	(0.21	)
Subordinated unitholders’ (basic and diluted)	$	0.10		$	(0.21	)
Weighted average number of limited partner units outstanding:
Common units (basic and diluted)		28,728			26,298
Subordinated units (basic and diluted)		7,146			7,146

See accompanying notes to the consolidated financial statements

QR ENERGY, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)


										Limited Partners
	Predecessor’s Capital			Class C Convertible Preferred Unitholders			General Partner			Public Common			Affiliated						Total Partners’ Capital
	Predecessor’s Capital			Class C Convertible Preferred Unitholders			General Partner			Public Common			Common			Subordinated			Total Partners’ Capital
Balances - December 22, 2010	$	354,734		$	—		$	—		$	—		$	—		$	—		$	354,734
Book value of IPO Assets contributed by the Predecessor		(223,736	)		—			—			—			137,051			86,685			—
Initital public offering		—			—			—			279,750			—			—			279,750
Deferred tax benefit as a result of IPO		—			—			—			134			101			64			299
Contributions from general partner		—			—			715			—			—			—			715
Contributions from the Predecessor (See Note 14)		53,034			—			—			—			—			—			53,034
Other contributions from affiliates (See Note 14)		482			—			—			—			113			71			666
Recognition of unit-based awards		—			—			—			20			—			—			20
Distribution to the Fund		—			—			—			—			(183,767	)		(116,233	)		(300,000	)
Net loss		(4,968	)		—			(7	)		(3,181	)		(2,396	)		(1,515	)		(12,067	)

Balances - December 31, 2010	$	179,546		$	—		$	708		$	276,723		$	(48,898	)	$	(30,928	)	$	377,151
Proceeds from over-allotment		—			—			—			41,963			—			—			41,963
Distribution to the Fund		—			—			—			—			(25,727	)		(16,273	)		(42,000	)
Contributions from the Predecessor (See Note 14)		8,986			—			—			—			—			—			8,986
Other contributions from affiliates (See Note 14)		11,708			—			—			—			12,366			7,822			31,896
Recognition of unit-based awards (See Note 11)		—			—			—			1,351			—			—			1,351
Reduction in units to cover individuals’ tax withholding		—			—			—			(215	)		—			—			(215	)
Distributions to unitholders		—			(3,424	)		(63	)		(30,673	)		(19,854	)		(12,557	)		(66,571	)
Book value of Transferred Properties contributed by the Predecessor		(249,331	)		—			—			—			—			—			(249,331	)
Fair value of Preferred Units issued to the Fund		—			354,500			—			—			—			—			354,500
Fair value of Preferred Units in excess of net assets received from the Fund		—			—			(102	)		(49,491	)		(32,380	)		(20,481	)		(102,454	)
Amortization of discount on increasing rate distributions		—			3,638			—			—			—			—			3,638
Noncash distribution to preferred unitholders		—			(3,638	)		—			—			—			—			(3,638	)
Management incentive fee earned		—			—			(1,572	)		—			—			—			(1,572	)
Net income		49,091			7,062			1,575			1,648			1,079			682			61,137

Balances - December 31, 2011	$	—		$	358,138		$	546		$	241,306		$	(113,414	)	$	(71,735	)	$	414,841

See accompanying notes to consolidated financial statements

PREDECESSOR - QA HOLDINGS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)


	General Partner			Limited Partners			Predecessor Partners’ Capital			Non-controlling Interest			Total Partners’ Capital
Balance - December 31, 2008		59			5,898			5,957			133,978			139,935
Contributions by partners		14			1,427			1,441			14,550			15,991
Distribution to partners		(9	)		(924	)		(933	)		(26,267	)		(27,200	)
Net loss		(79	)		(7,807	)		(7,886	)		(107,528	)		(115,414	)

Balance - December 31, 2009		(15	)		(1,406	)		(1,421	)		14,733			13,312
Contributions by partners		141			13,921			14,062			460,802			474,864
Distribution to partners		(9	)		(891	)		(900	)		(29,100	)		(30,000	)
Amortization of equity awards (See Note 11)		16			1,601			1,617			—			1,617
Net income		18			1,794			1,812			30,101			31,913

Balance - December 21, 2010	$	151		$	15,019		$	15,170		$	476,536		$	491,706

See accompanying notes to the consolidated financial statements

QR ENERGY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Partnership						Predecessor
	Year Ended December 31, 2011			December 22 to December 31, 2010			January 1 to December 21, 2010			Year Ended December 31, 2009
Cash flows from operating activities:
Net Income (loss)	$	61,137		$	(12,067	)	$	31,913		$	(115,414	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		78,354			2,130			66,482			16,993
Accretion of asset retirement obligations		2,702			77			3,674			3,585
Amortization of deferred financing costs		1,520			45			2,681			627
Recognition of unit-based awards		1,351			20			3,470			—
(Gain) loss on disposal of furniture, fixtures and equipment		—			—			(482	)		723
General and administrative expense contributed by affiliates		29,072			666			—			—
Impairment of oil and gas properties		—			—			—			28,338
Amortization of costs of derivative contracts		—			—			—			1,219
Unrealized (gains) losses on commodity derivative contracts (See Note 5)		(95,564	)		12,662			(5,598	)		108,164
Unrealized (gains) losses on investment in marketable equity securities		—			—			—			(5,640	)
Realized losses on investment in marketable equity securities		—			—			—			5,246
Deferred income tax expense		849			(71	)		—			—
Bargain purchase gain		—			—			—			(1,200	)
Equity in earnings of Ute Energy, LLC		—			—			(3,782	)		(2,675	)
Gain on equity share issuance		—			—			(4,064	)		—
Changes in operating assets and liabilities:
Accounts receivable and other assets		(29,029	)		(4,278	)		(39,727	)		15,052
Accounts payable and other liabilities		9,682			2,580			41,378			9,889

Net cash provided by (used in) operating activities		60,074			1,764			95,945			64,907

Cash flows from investing activities:
Additions to oil and gas properties		(55,480	)		(318	)		(56,133	)		(31,278	)
Acquisition of oil and gas properties		—			(77,763	)		(891,870	)		(43,300	)
Additions to furniture, equipment and other		—			—			(1,934	)		(1,456	)
Proceeds from sale of gas processing assets		—			—			890			—
Proceeds from sale of other assets		—			—			170			—
Increase in property reclamation deposit		—			—			—			(19	)
Investment in Ute Energy, LLC		—			—			—			(1,925	)
Proceeds from sales of marketable equity securities		—			—			—			6,233
Property acquisition deposit		—			—			(8,000	)		—
Proceeds from sale of properties		1,327			—			—			16,287

Net cash used in investing activities		(54,153	)		(78,081	)		(956,877	)		(55,458	)

Cash flows from financing activities:
Proceeds from underwriters’ exercise of overallotment option		41,963			—			—			—
Net proceeds from initial public offering (See Note 1)		—			279,750			—			—
Distributions to the Fund (See Note 1)		(42,000	)		(300,000	)		—			—
Contributions from the General Partner		715			—			—			—
Distrubutions to unitholders		(46,026	)		—			—			—
Intercompany financing from the Fund (See Note 14)		—			387			—			—
Contributions by partners and non-controlling interest owners		—			—			474,864			15,991
Distributions to partners and non-controlling interest owners		—			—			(30,000	)		(27,019	)
Contributions from the Predecessor		8,986			53,034			—			—
Proceeds from bank borrowings (See Note 7)		275,000			248,000			584,383			33,000
Repayment of debt assumed from the Fund (See Note 7)		(227,000	)		(200,000	)		—			—
Repayments on bank borrowings		—			—			(113,752	)		(35,300	)
Deferred financing costs		(2,321	)		(2,659	)		(12,047	)		—

Net cash provided by (used in) financing activities		9,317			78,512			903,448			(13,328	)

Increase (decrease) in cash and cash equivalents		15,238			2,195			42,516			(3,879	)
Cash and cash equivalents at beginning of period		2,195			—			17,156			21,035

Cash and cash equivalents at end of period	$	17,433		$	2,195		$	59,672		$	17,156

See accompanying notes to the consolidated financial statements

QR Energy, LP

Notes to Consolidated Financial Statements

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

NOTE 1 — ORGANIZATION AND OPERATIONS

QR Energy, LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed on September 20, 2010, to receive certain of the assets of QA Holdings, LP (the “Predecessor”). Our general partner is QRE GP, LLC (“QRE GP”). We operate the acquired assets through our wholly owned operating company QRE Operating, LLC (“OLLC”).

The Predecessor is a Delaware limited partnership, which commenced operations on April 1, 2006 for the primary purpose of acquiring, owning, enhancing and producing oil and gas properties through its subsidiaries. The Predecessor holds general partner interests in a collection of limited partnerships. Certain of the Predecessor’s subsidiary limited partnerships, (collectively, or in any combination, known as the “Fund”) comprise Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC. The Partnership and the Fund are managed by Quantum Resources Management, LLC (“QRM”), a full service management company originally formed to manage the oil and natural gas interests of the Predecessor. The general partner of the Predecessor and the individual entities included in the Fund is QA Global GP, LLC (“QA Global”).

On December 22, 2010 (the “Closing Date”), we completed our initial public offering (“IPO”) of 15,000,000 common units representing limited partner interests in the Partnership at $20.00 per common unit, or $18.70 per unit after payment of the underwriting discount. Net proceeds from the sale of the common units in the IPO were $279.8 million ($300 million less $19.5 million underwriters’ discount and $0.7 million structuring fee). IPO costs totaling $5.1 million were borne entirely by the Fund and are included in offering costs in the Predecessor’s consolidated statement of operations for the period January 1 to December 21, 2010.

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

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

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

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


Oil and gas properties, net	$	441,207
Gas processing equipment, net		251
Derivative instrument asset, net		64,671
Deferred tax asset		205
Long-term debt		(227,000	)
Asset retirement obligation		(26,294	)
Natural gas imbalance		(3,709	)

Book value of net assets		249,331
Purchase price adjustments		2,715

Net assets contributed by the Predecessor (1)	$	252,046

(1)

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

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

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

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

Services Agreement

On the Closing Date, we entered into a Services Agreement (the “Services Agreement”) with QRM, QRE GP and OLLC, pursuant to which QRM will provide the administrative and acquisition advisory services necessary to allow QRE GP to manage, operate and grow our business. Under the Services Agreement, from the Closing Date through December 31, 2012, QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. After the term of the Services Agreement, in lieu of the quarterly administrative services fee, QRE GP will reimburse QRM, on a quarterly basis, for the allocable expenses QRM incurs in its performance under the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM.

Omnibus Agreement

On the Closing Date, we entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among QRE GP, OLLC, the Fund, the Predecessor and QA Global. The Omnibus Agreement governs the following types of potential transactions:

•

The Fund agrees to provide us, for at least five years from the Closing Date, the first opportunity to purchase certain oil and gas assets it may offer for sale which consist of at least 70% proved developed producing reserves.

•

The Fund agrees to allow us the first option to participate in certain of its acquisition opportunities so long as 70% of the allocated value of the acquisition is attributable to proved developed producing reserves for a period of five years from the Closing Date.

•

Should QA Global or any of its affiliates close any new investment fund within two years from the Closing Date, the Omnibus Agreement shall be amended to include those entities as parties to the terms in the first two points above.

For additional discussion of the agreements listed above see Note 14.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2011 and 2010. These financial statements also include the results of our operations, cash flows and changes in partners’ capital for the year ended December 31, 2011, the period of December 22 to December 31, 2010 and those of our Predecessor for the periods of January 1 to December 21, 2010 and the year ended December 31, 2009. These consolidated financial statements include our subsidiary and all of the subsidiaries of the Predecessor.

Our consolidated statement of operations and consolidated statement of cash flows reflect activity since the Closing Date. We had no activity from September 20, 2010 (inception) to December 21, 2010.

These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. Certain line items previously reported on the Predecessor’s consolidated balance sheet, statements of operations and statement of cash flows have been combined based on materiality as allowed under GAAP and Securities and Exchange Commission (“SEC”) rules for financial statements and related disclosures. Certain reclassifications have been made to the previous years to conform to the 2011 presentation. These reclassifications do not affect the totals for current assets, current liabilities, noncurrent assets, noncurrent liabilities, revenue, operating expenses, other income (expenses), net income or cash flows.

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

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

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

Revised Balance Sheet

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

Revised Statement of Operations

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

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates particularly significant to the financial statements include the following:

•

Estimates of our reserves of oil, natural gas and natural gas liquids (“NGL”);

•

Future cash flows from oil and gas properties;

•

Depreciation, depletion and amortization expense;

•

Asset retirement obligations;

•

Fair values of derivative instruments;

•

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

•

Natural gas imbalances

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

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

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. The majority of cash and cash equivalents are maintained with several major financial institutions in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We use the specific identification method of providing allowances for doubtful accounts. As of December 31, 2011 and 2010, the allowance for doubtful accounts was not material to us or the Predecessor.

Property and Equipment

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

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

Prior to December 31, 2009, the ceiling calculation dictated that prices and costs in effect as of the last day of the quarter be held constant. The current ceiling calculation utilizes prices calculated as a twelve-month average price using first day of the month prices and costs in effect as of the last day of the quarter are held constant. Under both of these methods, the prices used are adjusted for basis or location differentials, product quality, energy content and transportation fees. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date.

There was no write-down required by us as of December 31, 2011. No write-down was required by the Predecessor for any quarter subsequent to March 31, 2009 through the period ended December 21, 2010. Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that we could incur a write-down.

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

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

Transactions Between Entities Under Common Control

Master limited partnerships (“MLPs”) from time to time enter into transactions whereby the MLP receives a transfer of certain assets from a sponsor (i.e. the Predecessor) with units issued to the sponsor and units sold to the public. We account for the net assets received using the carryover book value of the Predecessor as these are transactions between entities under common control. Our historical financial statements have been revised to include the results attributable to the assets contributed from our sponsor as if we owned such assets for all periods presented by the Partnership.

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

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

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

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

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

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

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

Oil and Gas Reserve Quantities

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. Our independent engineering firm also adheres to the SEC definitions when preparing their reserve reports.

Asset Retirement Obligations

We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. We incur these liabilities upon acquiring or drilling a well. GAAP requires entities to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depleted as a component of the full cost pool. The fair values of additions to the ARO liability are estimated using present value techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) inflation factors; and (iv) a credit-adjusted risk free rate. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance. Upon settlement of the liability, we adjust the full cost pool to the extent the actual costs differ from the recorded liability. See Note 6.

Deferred Financing Costs

Costs incurred in connection with the execution or modification of our credit facility are capitalized and charged to interest expense over the term of the revolver.

Derivatives

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

We have elected not to designate our derivatives as hedging instruments. Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Gains and losses on derivatives, including realized and unrealized gains and losses, are reported as nonoperating income or expense on the statements of operations in “gains (losses) on commodity derivatives.” Realized gains and losses represent amounts related to the settlement of commodity derivatives which are aligned with the underlying production. Unrealized gains and losses represent the change in fair value of the derivative instruments and are noncash items. See Note 4 and Note 5.

Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The credit worthiness of the counterparties is subject to continual review. We believe the risk of nonperformance by our counterparties is low. Full performance is anticipated, and we have no past-due balances from our counterparties. In addition, although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have properly presented all asset and liability positions without netting. See Note 5.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. A process is used to determine when expenses should be recorded for these contingencies and the estimate of reasonable amounts for the accrual. We closely monitor known and potential legal, environmental and other contingencies, and periodically determine when we should record losses for these items based on information available. Based on management’s assessment, no contingent liabilities have been recorded by the Partnership as of December 31, 2011 or 2010.

Concentrations of Credit and Market Risk

Credit risk

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

Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry. Neither we nor our Predecessor have experienced any material credit losses on such sales in the past.

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

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

In 2010, two customers accounted for 45% and 10% of the Predecessor’s oil, natural gas and NGL revenues. In 2009, three customers accounted for 24%, 12% and 10% of the Predecessor’s consolidated oil, natural gas and natural gas liquids revenues.

Market Risk

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

Preferred Units

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

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

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

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

Revenue Recognition

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on volumes sold to purchasers. Revenues from natural gas production may result in more or less than our pro rata share of production from certain wells. Under the sales method for natural gas sales and natural gas imbalances, when our sales volumes exceed our entitled share and the overproduced balance exceeds our share of remaining estimated proved natural gas reserves for a given property, we record a liability. See Note 12.

General and Administrative Expenses

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

Our potential sources of general and administrative expenses comprise the following types of expenses:

•

Direct general and administrative expenses incurred by QRM on our behalf (“Direct G&A”) and charged to us;

•

Administrative service fees payable by us to QRM during the term of the Services Agreement; and

•

Our share of allocable indirect general and administrative expenses incurred by QRM on behalf of the affiliates for which it provides management services which are in excess of the administrative services fee charged to us (“Allocated G&A”).

During the term of the Services Agreement, our general and administrative expenses, for any quarter therein, will comprise Direct G&A, the administrative service fee and Allocated G&A in excess of the administrative service fee. We will not be required to reimburse QRM for Allocated G&A in excess of administrative service fees during the term of the Services Agreement. Therefore, these allocated expenses will be recorded as capital contributions from the Fund in our Consolidated Statement of Partner’s Capital.

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

Allocated G&A for any quarter is calculated using the ratio of our quarterly production to the quarterly production of all QRM affiliates for which

QRM provides management services. For the period from December 22, 2010 to December 31, 2010, Allocated G&A was calculated using pro forma production volumes for the quarter ended December 31, 2010 as if the Fund had contributed the oil and gas properties on October 1, 2010. This ratio was applied to the total allocable indirect general and administrative expenses for the month of December 2010 and further reduced by the ratio of ten days to thirty-one days in order to estimate our Allocated G&A for the period from December 22, 2010 to December 31, 2010.

Management Incentive Fee

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

Income Taxes

We are treated as a partnership for federal income tax purposes. Generally, all of our federal taxable income and losses are reported on the income tax returns of the partners, and therefore, no provision for federal income taxes has been recorded in our accompanying consolidated financial statements.

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

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

Net Income (Loss) per Limited Partner Unit

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

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt. The carrying amounts of our financial instruments other than derivatives and long-term debt approximate fair value because of the short-term nature of the items. Derivatives are recorded at fair value. The carrying value of our debt approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. See Note 4.

Business Segment Reporting

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

Unit-Based Compensation

We have granted equity-classified restricted unit awards which we account for at fair value. Restricted unit awards, net of estimated forfeitures, are expensed over the requisite service period. As each award vests, an adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the vested awards. For unit-based awards that contain service conditions, compensation cost is recorded using the straight-line method.

As of December 31, 2011 and 2010, we have granted awards to individuals who performed services for us. All of the individuals receiving these units are employees of QRM performing services for us. We record these compensation costs as direct general and administrative expenses. See Note 11.

Accounting Policies Applicable to the Predecessor

Business Combinations

The Predecessor has accounted for all business combinations using the purchase method, in accordance with GAAP. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. The Predecessor has not recognized any goodwill from any business combinations.

Inventories

Inventories, consisting primarily of tubular goods and other well equipment held for use in the development and production of natural gas and crude oil reserves, are carried at the lower of cost or market, on a first-in first-out basis. Adjustments are made from time to time to recognize, as appropriate, any reductions in value.

Unproved Properties

Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether there is a probability of obtaining proved reserves in the future. When it is determined these properties have been promoted to a proved reserve category or there is no longer any probability of obtaining proved reserves from the properties, the costs associated with these properties is transferred into the amortization base to be included in depletion calculations. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geological data obtained relating to the properties. Where it is not practicable to assess properties individually as their costs are not individually significant, such properties are grouped for purposes of the periodic assessment.

Management Fees

The Predecessor pays an affiliated entity to provide management services for the operation and supervision of its limited partnerships. During 2010, the Predecessor determined it had over paid management fees by $0.8 million, spread over the last four years since inception in 2006. This amount was repaid in 2010 and thus reduced operating expenses. After evaluating the quantitative and qualitative aspects of these out-of-period errors, the Predecessor concluded its previously issued financial statements were not materially misstated and the effect of recognizing these adjustments in the 2010 financial statements were not material to the 2010 results of operations, financial position and cash flows.

Equity Investment

The Predecessor has an investment in an unconsolidated entity in which the Predecessor does not own a majority interest but does have significant influence over, and is accounted for under the equity method. Under the equity method of accounting, the Predecessor’s share of net income or loss from its equity affiliate is reflected as an increase (decrease) in its investment account in “Other noncurrent assets” and is also recorded as “Equity in earnings of Ute Energy, LLC” in “Other income or expenses, respectively.” Distributions from the equity affiliate are recorded as reductions of the Predecessor’s investment and contributions to the equity affiliate are recorded as increases of the Predecessor’s investment. The Predecessor reviews its equity method investment for potential impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in the value of the investment has occurred. See Note 15.

Employee Benefit Plan

The Predecessor has a 401(k) savings plan available to all eligible employees. The Predecessor matches 100% of employee contributions up to a certain percentage of the employee’s salary. Matching contributions vest immediately. The following table summarizes the Predecessor’s matching percentages and contributions for the periods indicated.


	Predecessor
	January 1 to December 21, 2010			Year Ended December 31, 2009
Percentage of employee’s salary		3	%		6	%
Matching contributions		0.3			0.6

Valuation-based compensation

The Predecessor has various forms of equity-based and liability-based compensation outstanding under its employee compensation plan. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period. Awards classified as liabilities are revalued at each reporting period and changes in the fair value of the options are recognized as compensation expense over the vesting periods of the awards. See Note 11 for further information.

Recent Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2010-03, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements (ASU 2010-06) requiring additional disclosures about fair value measurements including transfers in and out of Levels 1 and 2 and increased disclosure of different types of financial instruments. For the reconciliation of Level 3 fair value measurements, information about purchases, sales, issuances and settlements should be presented separately. This guidance is effective for annual and interim reporting periods beginning after December 15, 2009 for most of the new disclosures and for periods beginning after December 15, 2010 for the new Level 3 disclosures. Our adoption did not have a material impact on our consolidated financial statements.

On December 21, 2010, the FASB issued Accounting Standards Update No. 2010-29—Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations. The new guidance specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The update also expands the supplemental pro forma disclosures under Topic 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The update is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. This update was adopted by us on January 1, 2011 and will be considered if we enter into a business combination transaction.

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

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

NOTE 3 — ACQUISITIONS

Partnership Acquisitions

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

The Partnership’s Allocation of Melrose Acquisition by the Predecessor

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


Allocated cost of Predecessor’s acquisition	$	77,763

Oil and gas properties	$	82,781
Asset retirement obligations		(5,018	)

Total identifiable net assets	$	77,763

Predecessor Third Party Acquisitions

Predecessor Acquisition of Denbury Properties

On May 14, 2010, the Predecessor completed an acquisition to acquire certain oil and natural gas properties from Denbury Resources, Inc. (“Denbury”) for $893 million (the “Denbury Properties”). The Denbury Properties are located in the Permian Basin, Mid Continent and East Texas. Total proved reserves of the acquired properties were estimated to be 77 MMBoe as of May 14, 2010.

The acquisition qualifies as a business combination, and as such, the Predecessor estimated the fair value of these properties as of the acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants.

The Predecessor estimated that the fair value of the Denbury net assets acquired was approximately $918 million, with an associated ARO of $24.9 million, which the Predecessor considered to be representative of the price paid by a typical market participant. This measurement resulted in neither goodwill nor a bargain purchase gain. The acquisition related costs related to the Denbury acquisition were approximately $1.2 million and are recorded as acquisition evaluation costs during 2010.

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


Consideration given to Denbury:
Cash	$	888,785
Preferential rights (Not yet paid at December 31, 2010)		4,058

Total consideration	$	892,843

Recognized amounts of identifiable assets acquired and liabilities assumed:
Inventory (including hydrocarbons of $1,863)	$	6,384
Proved developed properties (1)		788,829
Proved undeveloped properties (1)		84,000
Unproved properties (1)		43,000
Suspended revenues payable		(4,521	)
Asset retirement obligations		(24,849	)

Total identifiable net assets	$	892,843

(1)

The Predecessor used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.

Summarized below are the consolidated results of operations for 2010 and 2009 for the Predecessor, on an unaudited basis, as if the acquisition had occurred on January 1 of each of the years presented. The unaudited pro forma financial information was derived from the Predecessor’s historical consolidated statement of operations and the statement of revenues and direct operating expenses for the Denbury Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Predecessor’s our expected future results of operations.


	2010				2009
	Actual		Pro Forma		Actual			Pro Forma
Revenues	$	253,386	$	343,190	$	72,801		$	233,778
Net Income (Loss)	$	31,913	$	98,455	$	(115,414	)	$	(94,962	)

Predecessor Acquisition of Jay Field Properties

The Predecessor signed and closed a purchase agreement on March 31, 2010 to acquire land within the Jay field from International Paper Company for $3.1 million.

Predecessor Acquisition of Shongaloo Properties

On January 28, 2009, the Predecessor completed an acquisition of 80 producing gas wells located in Arkansas and Louisiana (the “Shongaloo Properties”) for approximately $48.7 million from El Paso E&P Company, L.P. (“El Paso”). The acquisition was funded through cash calls to partners combined with borrowings under the Partnership’s credit facility. Total proved reserves of the acquired properties were estimated at 4.2 million barrels of oil equivalent at the date of acquisition.

The following table summarizes the consideration paid for the Shongaloo Properties and the fair value of the assets acquired and liabilities assumed as of January 28, 2009.


Consideration given to El Paso:
Cash	$	48,700

Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties (1)	$	51,600
Asset retirement obligations		(1,700	)
Bargain purchase		(1,200	)

Total identifiable net assets	$	48,700

(1)

Summarized below are the consolidated results of operations for the years ended December 31, 2009, on an unaudited pro forma basis, as if the acquisition had occurred on January 1 of each of the periods presented. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Predecessor and the statement of revenues and direct operating expenses for the Shongaloo Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of the Predecessor’s expected future results of operations.


	2009
	Actual			Pro Forma
Revenues	$	72,801		$	73,713
Net Loss	$	(115,414	)	$	(117,858	)

Predecessor 2009 Acquisition Pro Forma

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


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

NOTE 4 — FAIR VALUE MEASUREMENTS

Our financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Our financial and non-financial assets and liabilities that are being measured on a recurring basis are measured and reported at fair value.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:


Level 1—		Defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2—		Defined as inputs other than quoted prices in active markets that are either directly or indirectly observable for the asset or liability.

Level 3—		Defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions for the asset or liability.

Commodity Derivative Instruments — The fair value of the commodity derivative instruments are estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

Interest Rate Derivative Instruments — The fair value of the interest rate derivative instruments are estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

As required by GAAP, we utilize the most observable inputs available for the valuation technique utilized. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table sets forth, by level within the hierarchy, the fair value of our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 and 2010.


	Total		Level 1		Level 2		Level 3
Partnership - As of December 31, 2011
Assets from commodity derivative instruments	$	103,233	$	—	$	103,233	$	—
Assets from interest rate derivative instruments		20		—		20		—

	$	103,253	$	—	$	103,253	$	—

Liabilities from commodity derivative instruments	$	2,502	$	—	$	2,502	$	—
Liabilities from interest rate derivative instruments		23,973		—		23,973		—

	$	26,475	$	—	$	26,475	$	—

Partnership - As of December 31, 2010
Assets from commodity derivative instruments	$	36,302	$	—	$	36,302	$	—
Assets from interest rate derivative instruments		—		—		—		—

	$	36,302	$	—	$	36,302	$	—

Liabilities from commodity derivative instruments	$	55,773	$	—	$	55,773	$	—
Liabilities from interest rate derivative instruments		1,914		—		1,914		—

	$	57,687	$	—	$	57,687	$	—

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

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

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

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

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

On October 1, 2011, the Predecessor novated certain interest rate and commodity derivative instruments to us. These derivative instruments were accounted for at fair value of a $73.1 million net asset position (See Note 5). The Partnership’s Statement of Financial Position has been revised to include these derivative instruments for the periods presented. These derivative instruments are classified as Level 2 fair value measurements.

All fair values reflected above and on the consolidated balance sheets have been adjusted for nonperformance risk. The following table sets forth a reconciliation of the changes in the fair value of the Predecessor’s financial instruments classified as Level 3 in the fair value hierarchy:


	Predecessor
	January 1 to December 21,			Year Ended December 31,
	2010			2009
Balance at beginning of period	$	(59,699	)	$	—
Total gains or losses (realized or unrealized):
Included in earnings		25,563			(63,530	)
Purchases, issuances and settlements		(2,325	)		(45,853	)
Transfers in and out of Level 3		36,461			49,684

Balance at end of perod	$	—		$	(59,699	)

Changes in unrealized gains relating to derivatives still held at the end of period	$	—		$	(108,164	)

As part of a broad review by management of our financial statement disclosures and those of our Predecessor, management has determined, effective October 1, 2010, the fair values of the derivative instruments of our Predecessor should be classified as Level 2. As part of management’s review, the third-party valuation specialist used to value the Predecessor’s derivative instruments was consulted regarding the prices used to determine fair value. Management has determined the prices used by the third-party valuation specialist are directly observable inputs widely used by valuation specialists and easily obtainable from independent third parties via a subscription to their published price curves. Therefore, on October 1, 2010, the Predecessor transferred all derivative instruments which are measured on a recurring basis from Level 3 into Level 2.

NOTE 5 — DERIVATIVE ACTIVITIES

The Partnership

Interest Rate Derivatives

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

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

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

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

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

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

Commodity Derivatives

Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. As such, future earnings are subject to fluctuation due to changes in both the market price of oil, natural gas and natural gas liquids. We use derivatives to reduce our risk of changes in the prices of oil and natural gas. Our policies do not permit the use of derivatives for speculative purposes.

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

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

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

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

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

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


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

The Predecessor

Interest Rate Derivatives

During June 2010, the Predecessor entered into two tranches of derivative contracts with initial notional amounts of $275.0 million and $135.6 million to effectively fix the LIBOR component of the interest rate on its credit facility. Under the first tranche, the Predecessor made payments to the contract counterparties when the variable interest rate of the one-month LIBOR fell below the fixed rate of 2.74% during the period from June 2010 to December 2010. In addition, the Predecessor made payments to the contract counterparties when the one-month LIBOR fell below the fixed rate of 1.95% during the period from July 2010 to December 2010 under the second tranche.

During 2009, the Predecessor had interest rate derivatives for a notional amount of $100 million to effectively fix the LIBOR component of the interest rate on its credit facility at 4.29%. These derivatives expired on October 31, 2009.

Commodity Derivatives

In July 2010, the Predecessor entered into an oil collar related to forecast production from January 2014 through December 2015. In September 2010, the Predecessor entered into an offsetting oil collar to reduce hedge volumes from January 2015 through December 2015 associated with the July 2010 oil collar and entered into a swap contract covering the amount of offset volumes.

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


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

We have elected not to designate any of our derivatives as hedging instruments. As a result, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value of the derivatives are recorded as gains or losses in the accompanying consolidated statements of operations. The fair value of these derivatives was as follows as of December 31:


	Partnership
	2011				2010
	Asset Derivatives		Liability Derivatives		Asset Derivatives		Liability Derivatives
Commodity contracts	$	103,233	$	2,502	$	36,302	$	55,773
Interest rate contracts		20		23,973		—		1,914

	$	103,253	$	26,475	$	36,302	$	57,687

Commodity
Current	$	32,683	$	1,284	$	9,887	$	9,727
Noncurrent		70,550		1,218		26,415		46,046

	$	103,233	$	2,502	$	36,302	$	55,773

Interest
Current	$	—	$	8,285	$	—	$	1,159
Noncurrent		20	$	15,688		—		755

	$	20	$	23,973	$	—	$	1,914

Total Derivatives
Current	$	32,683	$	9,569	$	9,887	$	10,886
Noncurrent		70,570		16,906		26,415		46,801

	$	103,253	$	26,475	$	36,302	$	57,687

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


	Partnership						Predecessor
	Year Ended December 31, 2011			December 22 to December 31, 2010			January 1 to December 21, 2010			Year Ended December 31, 2009
Realized gains (losses):
Commodity contracts (1)	$	(72,053	)	$	(289	)	$	5,373		$	47,993
Interest rate swaps		(4,512	)		—			(4,808	)		(3,299	)

Total	$	(76,565	)	$	(289	)	$	565		$	44,694

Unrealized gains (losses):
Commodity contracts (1)	$	120,478		$	(12,068	)	$	8,204		$	(111,113	)
Interest rate swaps		(24,914	)		(594	)		(2,606	)		2,949

Total	$	95,564		$	(12,662	)	$	5,598		$	(108,164	)

Total gains (losses):
Commodity contracts	$	48,425		$	(12,357	)	$	13,577		$	(63,120	)
Interest rate swaps (2)		(29,426	)		(595	)		(7,414	)		(350	)

Total	$	18,999		$	(12,952	)	$	6,163		$	(63,470	)

(1)	Gains (losses) on commodity derivative contracts are located in other income (expense) in the consolidated statement of operations.

(2)	Losses on interest rate derivative contracts are recorded as part of interest expense and are located in other income (expense) in the consolidated statement of operations.

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

NOTE 6 — ASSET RETIREMENT OBLIGATIONS

The total undiscounted amount of future cash flows to settle our asset retirement obligations is estimated to be $222.2 million and $162.0 million at December 31, 2011 and 2010. We recorded a discounted total of approximately $43.4 million for future asset retirement obligations in connection with the conveyance of net assets from the Fund. Payments to settle asset retirement obligations occur over the lives of the oil and gas properties, estimated to be from less than one year to 61 years. Estimated cash flows have been discounted at our credit adjusted risk free rate of 5.59% and adjusted for inflation using a rate of 2.25%.

Changes in the asset retirement obligations are presented in the following table:


	Partnership						Predecessor
	Year Ended December 31, 2011			December 22 to December 31, 2010			January 1 to December 21, 2010
Beginning of period	$	43,414		$	38,319		$	35,244
Assumed in acquisitions		—			5,018			24,849
Revisions to previous estimates (1)		19,456			—			1,494
Liabilities incurred		377			—			—
Liabilities settled		(248	)		—			(747	)
Accretion expense		2,702			77			3,674

End of period	$	65,701		$	43,414		$	64,514
Less: Current portion of asset retirement obligations		(348	)		(4,166	)		(4,187	)

Asset retirement obligations - non-current	$	65,353		$	39,248		$	60,327

(1)	In 2011 we recorded upward revisions to previous estimates for our asset retirement obligations due to increases in future plugging and abandonment costs and changes to the remaining lives of our wells.

In 2011 we recorded upward revisions to previous estimates for our asset retirement obligations due to increases in future plugging and abandonment costs and changes to the remaining lives of our wells.

NOTE 7 — LONG-TERM DEBT

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


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

	$	500,000	$	452,000

(1)

As of December 31, 2011, we had availability under this facility of $129.6 million after giving effect to outstanding borrowings of $500 million and $0.4 million of outstanding letters of credit. As of December 31, 2010, we had availability under this facility of $75 million after giving effect to outstanding borrowings of $225 million.

(2)	As of December 31, 2010, the portion of the Predecessor’s credit facility collateralized by the Transferred Properties was $227 million.

The Partnership

On December 22, 2010, in connection with the IPO, the Partnership entered into a Credit Agreement along with QRE GP, OLLC as Borrower, and a syndicate of banks (the “Credit Agreement”)

The Credit Agreement provides for a five-year, $750.0 million revolving credit facility maturing on December 22, 2015, with a borrowing base of approximately $630.0 million as of December 31, 2011. The borrowing base will be subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year based on an engineering report with respect to our estimated oil, natural gas and NGL reserves, which will take into account the prevailing oil, natural gas and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. On July 13, 2011, we received an interim borrowing base redetermination under our Credit Agreement which increased the borrowing base to $330.0 million. We requested and received this interim redetermination as a result of improvements in our net derivative position due to the buyup of our existing oil fixed price swap contracts in June 2011. On October 3, 2011, we amended our revolving credit facility to, among other things, increase the borrowing base by $300.0 million, resulting in a total borrowing base of $630 million. This amendment also modified certain provisions and covenants of to allow for the successful consummation of the transactions related to the Purchase Agreement, the issuance of the Preferred Units and the related entry into the amendment to our partnership agreement (See Note 14). The administrative agent of our Credit Agreement has accepted this amendment in lieu of our semiannual redetermination required on November 1, 2011. Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum.

As of December 31, 2011 and 2010, we had $500.0 million and $225.0 million of borrowings outstanding and $129.6 million of borrowing availability as of December 31, 2011. In June 2011, we borrowed $41 million in connection with the modification of certain commodity derivative contracts and in October 2011, we borrowed an additional $234 million to repay the $227 million of debt assumed in connection with the Transferred Properties.

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable debt obligation during the year ended December 31, 2011:


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

The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and to provide audited financial statements within 90 days of year end and quarterly financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of its forecasted production attributable to proved developed producing reserves and (ii) 85% of its forecasted production from total proved reserves for the next two years and 75% of its forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of December 31, 2011, we were in compliance with all of the Credit Agreement covenants.

In connection with the IPO, we assumed $200 million of the Predecessor’s debt. On the Closing Date, we repaid the assumed debt with the proceeds from our revolving credit facility disclosed above.

The Predecessor

In September 2006, the Predecessor, through its subsidiaries QRA1, QRFC, and Black Diamond entered into three separate five-year revolving credit agreements with a syndicated bank group (the “Predecessor Credit Facilities”).

The Credit Facilities for QRA1 and Black Diamond were held by mortgages on their oil and gas properties and related assets. QRFC’s credit facility was held by the oil and gas properties owned by QAC.

Borrowings under the Predecessor Credit Facilities bore interest at the Alternative Base Rate (ABR) or the Eurodollar Rate plus a margin based on the borrowing base utilization. The ABR is defined as the higher of the prime rate or the sum of the Federal Funds Effective Rate plus 0.5%. The Eurodollar Rate is defined as the applicable British Bankers’ Association London Interbank Offered Rate (LIBOR) for deposits in U.S. dollars.

On May 14th, 2010 the Predecessor terminated its existing credit facilities and, through three of its subsidiaries, entered into three separate four-year revolving credit agreements. All outstanding loans under the previous credit facility were repaid in full from borrowings from the new credit facilities and all remaining unamortized loan costs totaling $0.7 million were written off. The combined new credit facilities had a maximum commitment of $850 million and a conforming borrowing base of $650 million. In conjunction with the amendments, the Predecessor incurred $11.5 million of debt issuance costs which were capitalized and are being amortized over the term of the agreements. Concurrent with the IPO, the Predecessor’s borrowing base was reduced to $415 million.

The credit agreements require the Predecessor to maintain a leverage ratio of not more than 4.5 to 1.0 currently, decreasing to 4.0 to 1.0 beginning with the period ended September 30, 2011 and continuing through maturity, and a current ratio of not less than 1.0 to 1.0. Additionally, the credit agreements contain various covenants and restrictive provisions which limit the Predecessor’s ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and require delivery of audited financial statements within 120 days of the end of the fiscal year and quarterly financial statements within 45 days of the end of each quarter. The credit agreements also provide limits on the amount of commodity derivative contracts the Predecessor may enter into, in particular prohibiting the Predecessor from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of its forecasted production attributable to proved developed producing reserves and (ii) 85% of its forecasted production from total proved reserves for the next two years and 75% of its forecasted production thereafter. If the Predecessor fails to perform its obligations under these and other covenants, the revolving credit commitment may be terminated and any outstanding indebtedness under the credit agreement, together with accrued interest, could be declared immediately due and payable. As of December 31, 2010, the Predecessor was in compliance with all covenants in its credit agreements, however, the Predecessor did not provide its audited financial statements by April 30, 2011 for which it sought and received a waiver to extend this reporting requirement by 45 days.

NOTE 8 — COMMITMENTS AND CONTINGENCIES

Services Agreement

The Partnership

We have entered into a Services Agreement with QRM as described in Note 14, under which, QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. The Partnership has no other commitments as of December 31, 2011.

Operating Lease Commitments

The Predecessor

Approximately 87% of the Predecessor’s future minimum rental payments are derived from the Houston corporate office space sublease which commenced September 1, 2009 and terminates December 31, 2012. The leasing agreement contains a four month rent holiday to be taken from the commencement date. A $1.6 million fee was paid by the Predecessor to terminate the Denver corporate office space lease on November 15, 2009. Total rental expense for the Predecessor for the period from January 1, 2010 to December 21, 2010 and for 2009 was $0.8 million and $3.0 million.

Legal Proceedings

The Partnership

In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We currently have no legal proceedings with a probable adverse outcome. Therefore, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

In addition, we do not have any working interests in the Jay Field and are therefore not a party to the Predecessor’s pending legal proceedings discussed below.

The Predecessor

The Predecessor was involved in various suits and claims arising in the normal course of business. The Predecessor related entities owning working interests in the Jay Field, brought suit against Santa Rosa County, Florida, protesting the County’s assessed value for the Jay interests for calendar years 2009 and 2010. Santa Rosa County assessed the value of the Jay Field at approximately $92 million for each year. The Predecessor made good faith payments for each calendar year based on valuations of $5 million and $45 million. If the County were to prevail in its assessed value, the resulting additional tax to the Predecessor will be approximately $1.3 million for 2009 and $0.8 million for 2010. The Predecessor believed it had a sound case to prevail on an assessed value lower than that asserted by Santa Rosa County for each calendar year.

In April 2011, the Predecessor received a demand letter from a third-party for severance taxes related to production for the past ten years from an operating unit. The total amount claimed is approximately $2 million. Based on an initial evaluation, the Predecessor believed there is no evidence to support a material liability.

In management’s opinion, the ultimate outcome of these items would not have a material adverse effect on the Predecessor’s consolidated results of operations, financial position or cash flows. Based on management’s assessment, no contingent liabilities were recorded as of December 21, 2010.

NOTE 9 — PARTNERS’ CAPITAL

Initial Public Offering

On December 22, 2010, we completed our IPO of 15,000,000 common units representing limited partner interests in us at $20.00 per common unit, or $18.70 per unit after payment of the underwriting discount. In connection with the IPO, the Fund contributed to us certain fields in the Permian Basin and the Ark-La-Tex, Mid-Continent and Gulf Coast areas. In exchange, the Fund received, either directly or through our assumption of its indebtedness, all of the net proceeds of the IPO. Upon completion of the IPO, we had 26,297,737 common units, 7,145,866 subordinated units and 35,729 general partner units outstanding. Our common units are traded on the NYSE under the symbol “QRE.”

All of the subordinated units and 11,297,737 common units are owned by the Fund and all of the general partner units are owned by affiliates of the Fund.

Units Outstanding

As of December 31, 2011, our outstanding partnership interests consisted of 16,666,667 Class C Preferred Units, 28,590,016 outstanding common units and 7,145,866 outstanding subordinated units, representing a 99.9% limited partnership interest in us, and a 0.1% general partnership interest represented by 35,729 general partner units.

As of December 31, 2010, our outstanding partnership interests consisted of 26,297,737 outstanding common units and 7,145,866 outstanding subordinated units, representing a 99.9% limited partnership interest in us, and a 0.1% general partnership interest comprising 35,729 general partner units.

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


					Limited Partners
	Preferred Units		General Partner		Public Common			Affiliated
	Preferred Units		General Partner		Public Common			Common		Subordinated
Balance - December 22, 2010		—		—		—			—		—
Units issued to the Predecessor in exchange for IPO Assets		—		—		—			11,297,737		7,145,866
Initial public offering		—		—		15,000,000			—		—
Units issued to the general partner		—		35,729		—			—		—

Balance - December 31, 2010		—		35,729		15,000,000			11,297,737		7,145,866
Underwriters’ exercise of over-allotment		—		—		2,250,000			—		—
Units awarded under our Long Term Incentive
Performance Plan		—		—		52,798			—		—
Reduction in units to cover individuals’ tax witholdings		—		—		(10,519	)		—		—
Preferred Units issued to Predecessor in exchange for Transferred Properties		16,666,667		—		—			—		—

Balance - December 31, 2011		16,666,667		35,729		17,292,279			11,297,737		7,145,866

Class C Preferred Units

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

Holders may convert the Preferred Units to common units on a one-to-one basis prior to October 3, 2013, 30 consecutive trading days during which the volume-weighted average price for our common units equals or exceeds $27.30 per common unit. In addition, holders may convert the Preferred Units to common units on a one-to-one basis anytime on or after October 3, 2013.

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

We may force conversion on a one-to-one basis after October 3, 2016, provided the conversion is in the 30 calendar days following 30 consecutive trading days during which the volume-weighted average price for common units equals or exceeds $27.30 and an effective shelf registration statement covering resales for the converted units is in place.

Registration Rights Agreement

In connection with the acquisition of the Transferred Properties, on October 3, 2011, we entered into a Registration Rights Agreement with the Fund (the “Registration Rights Agreement”), which granted certain registration rights to the Fund, including rights to (a) cause the Partnership to file with the SEC up to five shelf registration statements under the Securities Act for the resales of the common units to be issued upon conversion of the Preferred Units, and in certain circumstances, the resales of the Preferred Units, and (b) participate in future underwritten public offerings of the our common units.

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

These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.

Common Units

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

Pursuant to our partnership agreement, if at any time QRE GP and its affiliates own more than 80% of the outstanding common units, QRE GP has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. QRE GP may assign this call right to any of its affiliates or to us.

Subordinated Units

The principal difference between our common and subordinated units is that, in any quarter during the subordination period, the subordinated units are entitled to receive the minimum quarterly distribution of $0.4125 per unit ($1.65 per unit on an annualized basis) only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.

The subordination period will end on the earlier of:

•

the later to occur of (i) the second anniversary of the closing of our IPO and (ii) such date as all arrearages, if any, of distributions of the minimum quarterly distribution on the common units have been eliminated; and

•

the removal of QRE GP other than for cause, provided that no subordinated units or common units held by the holders of the subordinated units or their affiliates are voted in favor of such removal.

QRE GP Interest

QRE GP owns a 0.1% interest in us. This interest entitles QRE GP to receive distributions of available cash from operating surplus as discussed further below under Cash Distributions. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and QRE GP will receive.

QRE GP has sole responsibility for conducting our business and managing our operations. QRE GP’s board of directors and executive officers will make decisions on our behalf.

Allocations of Net Income

Net income is allocated to the preferred unitholders to the extent distributions are made to them during the period with the remaining income being allocated between QRE GP and the common and subordinated unitholders in proportion to their pro rata ownership during the period.

Cash Distributions

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

Our partnership agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. We intend to fund a portion of our capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.

QRE GP owns a 0.1% general partner interest in us, represented by 35,729 general partner units. QRE GP has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. QRE GP’s initial 0.1% interest in these distributions will be reduced if we issue additional units in the future and QRE GP does not contribute a proportionate share of capital to us to maintain its 0.1% general partnership interest.

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

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

•

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

(i)

provide for the proper conduct of our business,

(ii)

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

(iii)

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

•

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

•

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

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

•

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

•

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

•

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

•

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

After Subordination Period. Our partnership agreement requires that after the subordination period, we make distributions of available cash from operating surplus for any quarter to QRE GP and all unitholders in accordance with their percentage interest (other than preferred unitholders), pro rata

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


Date Paid	For the period ended	Distributions to Preferred Unitholders		Distributions per Preferred Unit (1)		General Partner		Public Common		Affiliated				Total Distributions to Other Unitholders (2) (3)		Distributions per other units (2) (3)
Date Paid	For the period ended	Distributions to Preferred Unitholders		Distributions per Preferred Unit (1)		General Partner		Public Common		Common		Subordinated		Total Distributions to Other Unitholders (2) (3)		Distributions per other units (2) (3)
(In thousands, except per unit amounts)
February 11, 2011	December 31, 2010	$	—	$	—	$	2	$	779	$	506	$	320	$	1,607	$	0.0448
May 13, 2011	March 31, 2011		—		—		15		7,186		4,660		2,948		14,809		0.4125
August 12, 2011	June 30, 2011		—		—		15		7,184		4,660		2,948		14,807		0.4125
November 11, 2011	September 30, 2011		—		—		15		7,180		4,660		2,948		14,803		0.4125
February 10, 2012	December 31, 2011		3,424		0.2054		16		8,344		5,368		3,393		17,121		0.4750

(1)	Preferred Units were prorated a quarterly distribution for the portion of the fourth quarter beginning on October 3, 2011 through December 31, 2011 in accordance with the Partnership Agreement.

(2)	The first quarter 2011 minimum quarterly distribution was prorated for the 10 day period from December 22, 2010 to December 31, 2010 in accordance with the Partnership Agreement.

(3)	An increase in the quarterly distribution to $0.475 was declared by the board of directors on October 3, 2011 and accrued in the fourth quarter 2011.

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

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


	2011			December 22 to December 31, 2010
Net income (loss)	$	61,137		$	(12,067	)
Net (income) loss attributable to predecessor operations		(49,091	)		4,968
Distribution on Class C convertible preferred units		(7,062	)		—

Net income (loss) available to other unitholders		4,984			(7,099	)
Less: general partner’s interest in net income (loss)		1,575			(7	)

Limited partner’s interest in net income (loss)	$	3,409		$	(7,092	)
Common unitholders’ interest in net income (loss)	$	2,730		$	(5,577	)
Subordinated unitholders’ interest in net income (loss)	$	679		$	(1,515	)
Net income (loss) per limited partner unit:
Common unitholders’ (basic and diluted)	$	0.10		$	(0.21	)
Subordinated unitholders’ (basic and diluted)	$	0.10		$	(0.21	)
Weighted average number of limited partner units outstanding (1):
Common units (basic and diluted)		28,728			26,298
Subordinated units (basic and diluted)		7,146			7,146

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

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

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

NOTE 11 — EQUITY-BASED COMPENSATION

Partnership Unit - Based LTIP Plan

On December 22, 2010, in connection with the closing of the IPO, the Board of Directors of QRE GP adopted the QRE GP, LLC Long Term Incentive Plan (the “Plan”) for employees, officers, consultants and directors and consultants of QRE GP and those of its affiliates, including QRM, who perform services for us. The Plan consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation to employees providing services to us and to align the economic interests of such employees with the interests of our unitholders. The Plan limits the number of Common Units that may be delivered pursuant to awards under the plan to 1.8 million units. Common Units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards.

On December 22, 2010, we granted restricted unit awards to individuals who performed services for us in support of the completion of our IPO. The fair value of the common unit award granted was calculated based on the closing price of our common units on the grant date, $20.03 per common unit, which we expect will be recognized in expense over vesting periods of up to five years.

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

On January 4, 2011, we granted common unit awards of 3,750 units to each of our two independent directors. These units vested immediately upon grant. The fair value of the common unit awards granted was calculated based on the closing price of our common units on the grant date, $20.20 per common unit.

On March 9, 2011, we granted restricted common unit awards of 8,985 units each to two of our named executive officers. The fair value of the common unit awards granted was calculated based on the closing price of our common units on the grant date, $22.26 per common unit, and we expect to recognize this in expense over the three year vesting period.

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

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

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


	Number of Unvested Restricted Units			Weighted Average Grant-Date Fair Value per unit
Unvested units, December 22, 2010		—		$	—
Granted		148		$	20.03
Forfeited		—		$	—
Vested		—		$	—

Unvested units, December 31, 2010		148		$	20.03
Granted		215		$	20.51
Forfeited		(39	)	$	20.75
Vested		(53	)	$	20.31

Unvested units, December 31, 2011		271		$	20.26

Predecessor Compensation Plans

Long-Term Incentive Compensation Plan

In April 2009, the Predecessor adopted a Long-Term Incentive Compensation Plan “Agreement” for its executive officers and other key employees. These employees receive certain interest, as defined below, in distributions received by the Predecessor through its subsidiaries. During the period ended December 21, 2010, the Predecessor recognized compensation expense of $1.6 million in equity-classified awards and $1.9 million in liability-classified awards. These awards are based on certain performance measurements and service. Interests awarded are based on the type of interest held by the Predecessor or its subsidiaries as follows:

The Predecessor General Partnership (Funded) Interest

The Predecessor contributes to the Fund 3% of all equity contributions made to the Fund and receives 3% of any distributions made by the Fund (“GP Funded Interest”). A special class of limited partnership interest in the general partner of the Fund was created to give executive officers and other key employees an interest in the GP Funded Interest after the Predecessor has recouped a portion of its total capital contributed to the Fund until each employee has received a cumulative amount equal to his vested share of the GP Funded Interest. Employees awarded this interest vest 15% on each of the first five anniversaries of the effective date and the remaining 25% vests if employed upon the disposition of substantially all of the assets of the Fund.

Employees of the Predecessor received GP Funded Interest grants in 2010 and 2009. The estimated fair value, at the date of the grant, is recognized as long-term incentive compensation in general and administrative expense in the statement of operations ratably as the awards vest. Estimated forfeitures will be adjusted to reflect actual forfeitures in future periods. We account for these profits interests as equity awards, and we estimated the fair value of these interests using a Probability Weighted Expected Return Model (“PWERM”). The PWERM forecasts expected cash flow scenarios specific to each award, assigns probability weights to these scenarios, then discounts the sum of the probability weighted cash flows to a grant date present value using a risk adjusted discount rate. The scenarios represent possible outcomes for each award based on assumptions about investment horizon, cash flow amounts and timing, asset values, commodity prices, equity investment amounts, and return on investment. The Predecessor assumed a zero percentage forfeiture rate for all years when determining the fair value of the GP Funded Interest.

The estimated aggregate fair value of the equity component of the awards at the date of grant was $0.3 million and $0.7 million for awards granted during the periods ended December 21, 2010 and December 31, 2009 respectively. The Predecessor incurred non-cash compensation expense related to the GP Funded Interest awards of $0.2 million and $0.1 million for the periods ended December 21, 2010 and December 31, 2009. The 2009 expense was recorded in 2010. Refer to “Out-of-Period Adjustments” further below. In addition there is a liability component to the award related to the 25% that vests and will be expensed upon substantial disposition of the Fund assets with a fair value of $0.7 million at December 21, 2010.


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

Nonvested GP Funded Interests as of December 31, 2009		72.82	%	$	57,512
Granted		22.05	%		88,206
Forfeited		0.00	%

Nonvested GP Funded Interests as of December 21, 2010		94.87	%	$	145,718

Activity related to the GP Funded Interests is as follows:
Nonvested GP Funded Interests as of December 31, 2008					0.00	%
Granted					72.82	%
Vested					0.00	%
Forfeited					0.00	%

Nonvested GP Funded Interests as of December 31, 2009					72.82	%
Granted					22.05	%
Vested					-10.92	%
Forfeited					0.00	%

Nonvested GP Funded Interests as of December 21, 2010					83.95	%

The Predecessor General Partner Promote Interest

After all investors in the Fund have received a return of their equity contributions plus a return of 8%, the Predecessor is entitled to receive 14% of all amounts distributed thereafter, including a catch-up on the amount distributed as part of the 8% return to all investors (“GP Promote”). A special class of limited partnership interest was created to award executive officers and other key employees 100% of the interest in the GP Promote until distributions attributable to the GP Promote aggregate $12,800,000 and, thereafter 39% of the distributions attributable solely to the GP Promote. Employees awarded this interest vest 15% on each of the first five anniversaries of the effective date and the remaining 25% vests if employed upon the disposition of substantially all of the assets of the Fund.

Employees of the Predecessor received GP Promote grants in 2010 and 2009.The estimated fair value, at the date of the grant, is recognized as compensation in general and administrative expense in the statement of operations ratably as the awards vest. Estimated forfeitures will be adjusted to reflect actual forfeitures in future periods. In accordance with GAAP, we estimated the fair value of these interests using a Probability Weighted Expected Return Model (“PWERM”). The PWERM forecasts expected cash flow scenarios specific to each award, assigns probability weights to these scenarios, then discounts the sum of the probability weighted cash flows to a grant date present value using a risk adjusted discount rate. The scenarios represent possible outcomes for each award based on assumptions about investment horizon, cash flow amounts and timing, asset values, commodity prices, equity investment amounts, and return on investment. The Predecessor assumed a zero percentage forfeiture rate for all years when determining the fair value of the GP Promote.

The estimated aggregate fair value of the equity component of the awards at the date of grant was $0.3 million and $0.9 million for awards granted during the periods ended, December 21, 2010 and December 31, 2009, respectively. The Predecessor incurred non-cash compensation expense of $0.2 million and $0.1 million for the periods ended December 21, 2010 and December 31, 2009. The 2009 expense was recorded in 2010. Refer to “Out –of-Period-Adjustments” further below. No amounts have been forfeited. In addition, there is a liability component to the award related to the 25% that vests and will be expensed upon substantial disposition of the Fund assets with a fair value of $1.1 million at December 21, 2010.

Activity related to the GP Promote Interests is as follows:


	% of Interest Granted			Weighted Average Grant Date Fair Value Per 1%
Nonvested GP Promote Interests as of December 31, 2008		0.00	%	$	—
Granted		78.83	%		71,534
Forfeited		0.00	%

Nonvested GP Promote Interests as of December 31, 2009		78.83	%	$	71,534
Granted		17.45	%		97,544
Forfeited		0.00	%

Nonvested GP Promote Interests as of December 21, 2010		96.28	%	$	169,078

Activity related to the GP Promote Interests is as follows:
Nonvested GP Promote Interests as of December 31, 2008					0.00	%
Granted					78.83	%
Vested					0.00	%
Forfeited					0.00	%

Nonvested GP Promote Interests as of December 31, 2009					78.83	%
Granted					17.45	%
Vested					-10.92	%
Forfeited					0.00	%

Nonvested GP Promote Interests as of December 21, 2010					85.36	%

Purchase/Carry Interests

The Predecessor, through a subsidiary purchases a 2% interest in each property acquired by the Fund and also receives a 2 % carried interest in each property acquired by the Fund. A special class of limited partnership interests in the Predecessor was created and awarded on April 1, 2009 to two senior executive officers in the aggregate of 19.5% of the distributions made by the subsidiary (“Purchase/Carry Interest”) excluding an amount that represented the net agreed value of the subsidiary assets on the date of grant. The Purchase/Carry Interests vest (i) 50% upon the effective date of the grant (ii) an additional 7.5% on each of the first five anniversaries following April 1, 2009 and (iii) the remaining 12.5% vest if employed upon the disposition of substantially all of the assets of the Fund. In addition, the executives must be employed as of the Fund’s investment period, currently June 30, 2011, and the Fund must achieve a 1.5X return on its total capital investment, as defined by the Agreement.

The estimated fair value, at the date of the grant, is recognized as compensation in general and administrative expense in the statement of operations ratably as the awards vest. Estimated forfeitures will be adjusted to reflect actual forfeitures in future periods. In accordance with GAAP, we have accounted for the fair value of the Purchase/Carry Interests as equity awards, and we estimated the fair value of these interests using a Probability Weighted Expected Return Model (“PWERM”). The PWERM forecasts expected cash flow scenarios specific to each award, assigns probability weights to these scenarios, then discounts the sum of the probability weighted cash flows to a grant date present value using a risk adjusted discount rate. The scenarios represent possible outcomes for each award based on assumptions about investment horizon, cash flow amounts and timing, asset values, commodity prices, equity investment amounts, and return on investment. The Predecessor assumed a zero percentage forfeiture rate for all years when determining the fair value of the Purchase/Carry Interests.

The estimated aggregate fair value of the equity component of the awards at the date of grant was $1.8 million The Predecessor incurred non-cash compensation expense of $0.6 million and $0.4 million for the periods ended December 21, 2010 and December 31, 2009. The 2009 expense was recorded in 2010. Refer to “Out-of-Period Adjustments” further below. No amounts have been forfeited. In addition, there is a liability component to the award related to the 12.5% that vests and will be expensed upon substantial disposition of the Fund assets with a fair value of $0.3 million at December 21, 2010.

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


	% 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 Puchase/Carry Interests as of December 31, 2009		100.00	%	$	13,278
Granted		0.00	%		—
Forfeited		0.00	%

Nonvested Purchase/Carry Interests as of December 21, 2010		100.00	%	$	13,278

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

Nonvested Puchase/Carry Interests as of December 31, 2009					100.00	%
Vested					-7.50	%
Forfeited					0.00	%

Nonvested Purchase/Carry Interests as of December 21, 2010					92.50	%

Performance Cash Deferred Compensation Plan

In April 2009, the Predecessor established a bonus plan (“Bonus Pool”) for certain key employees to award these employees upon the Fund achieving certain performance targets and service by the employee. If the Fund achieves a 1.75X return on its total capital investment (“1.75X ROI”) as defined in the plan, a Bonus Pool of $12.5 million will be established for the employees. If the Fund achieves a 2.0X return on its capital investment the Bonus Pool will be increased to $15 million.

Each employee will vest in a pro-rata share of the Bonus Pool, as determined by their offer letter, 15% per year from the date of the grant for five years and 25% upon the disposition of substantially all of the assets of the Fund. The employee must remain employed for the vesting period and must be employed on the date upon which the disposition of substantially all of the assets of the Fund occurs.

During the fourth quarter 2010, the Predecessor determined that it was probable to meet the 1.75X ROI and has recorded $1.9 million of compensation expense in general and administrative expenses in the statement of operations for the year ended December 21, 2010. These awards are liability-classified awards as they will ultimately settle in cash.

Out of Period Adjustments

During 2010 the Predecessor recorded adjustments related to 2009 which decreased its income for 2010 by $0.6 million as a result of compensation expense which should have been recorded in 2009.

After evaluating the quantitative and qualitative aspects of these errors, the Predecessor concluded its previously issued financial statements were not materially misstated and the effect of recognizing these adjustments in the 2010 financial statements were not material to the 2010 results of operations, financial position and cash flows.

NOTE 12 – ACCRUED AND OTHER LIABILITIES

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


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

	$	50,027	$	8,021

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

(2)

We account for our natural gas imbalances under the sales method. We had overproduced liabilities of $4.0 million and $5.4 million included in accrued liabilities on our consolidated balance sheet as of December 31, 2011 and December 31, 2010 for overproduced positions which were beyond ultimate recoverability of remaining natural gas reserves. As of December 31, 2011, our gross underproduced natural gas position was approximately $1.1 million (1.6 MMcf) and our gross overproduced natural gas position was approximately $4.0 million (2.3 MMcf). These gross positions were valued at $3.01 per Mcf for underproduced natural gas positions and $2.96 per Mcf for overproduced natural gas positions without regard to remaining natural gas reserves. As of December 31, 2010, our gross underproduced natural gas position was approximately $1.8 million (597 MMcf) and our gross overproduced natural gas position was approximately $5.4 million (1,854 MMcf). These gross positions were valued at $4.00 per Mcf without regard to remaining natural gas reserves.

NOTE 13 — SIGNIFICANT CUSTOMERS

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


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

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

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

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

NOTE 14 — RELATED PARTY TRANSACTIONS

Ownership in QRE GP by the Management of the Fund and its Affiliates

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

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

Contracts with QRE GP and Its Affiliates

We have entered into agreements with QRE GP and its affiliates. The following is a description of those agreements.

Contribution Agreement

On December 22, 2010, in connection with the closing of the IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement by and among the Partnership, QRE GP, OLLC and the Fund:

•

QRE GP agreed to contribute $0.7 million to the Partnership to maintain its 0.1% general partner interest in the Partnership, represented by 35,729 general partner units; and

•

The Fund contributed net assets of $223.7 million to the Partnership in exchange for 11,297,737 common and 7,145,866 subordinated limited partner units and a $300 million cash distribution. See Note 1.

QRE GP’s capital contribution remained as a receivable on the Partnership’s books as of December 31, 2010 and was received by the Partnership in January 2011.

Services Agreement

On December 22, 2010, in connection with the closing of the IPO, we entered into the Services Agreement with QRM, QRE GP and OLLC, pursuant to which QRM will provide the administrative and acquisition advisory services necessary to allow QRE GP to manage, operate and grow our business. We do not have any employees. The Services Agreement requires that employees of QRM (including the persons who are executive officers of QRE GP devote such portion of their time as may be reasonable and necessary for the operation of our business. The executive officers of QRE GP currently devote a majority of their time our business, and we expect them to continue to do so for the foreseeable future.

Under the Services Agreement, from the closing of the IPO through December 31, 2012, QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee.

The term of the Services Agreement comprises an initial term from December 22, 2010 to December 31, 2010 and continues on a year-to-year basis thereafter unless terminated after the initial term by us or QRM. After the term of the Services Agreement ends, in lieu of the quarterly administrative services fee, QRE GP will reimburse QRM, on a quarterly basis, for the allocable expenses QRM incurs in its performance under the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated by QRM to its affiliates.

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

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


Beginning balance as of December 22, 2010	$	—
Ad valorem taxes paid by the Fund on our behalf		(22	)
Interest paid by the Fund on our behalf		(263	)
Debt issue costs paid by the Fund on our behalf		(102	)

Intercompany financing from the Fund		(387	)
Administrative services fee due to the Fund		(55	)

Net affiliate payable as of December 31, 2010		(442	)
Revenues and other increases (1) (2)		130,946
Expenditures		(70,367	)
Settlements from the Fund		(56,403	)

Net affiliate receivable as of December 31, 2011	$	3,734

(1)	Includes $1.6 million in overhead producing credits and $1.3 million of proceeds from the sale of oil and gas leases received by the Fund on our behalf.

(2)	Includes $2.7 million in purchase price adjustments receivable from the Fund related to natural gas imbalances included with the Transferred Properties on October 3, 2011.

Other Contributions to Partners’ Capital

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


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

Total other contributions from affiliates	$	31,896	$	666

(1)	Represents our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us for the IPO Assets during 2011 and for the Transferred Properties effective October 1, 2011 through December 31, 2011.

(2)	Represents our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us for the Transferred Properties from January 1 to December 31, 2011.

(3)

On February 28, 2011, the Fund novated to us fixed-for-floating interest rate swaps covering $225.0 million of borrowings under our revolving credit facility. The Fund also novated to us on July 1, 2011 natural gas basis swaps with contract dates until 2015. The fair value of these derivative instruments was a net asset position.

(4)	QRM also incurred prepaid insurance on our behalf, but not reimbursable by us.

Cash Contributions from the Predecessor

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


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

Cash contributions from the Predecessor	$	8,986		$	53,034

Omnibus Agreement

On December 22, 2010, in connection with the closing of our IPO, we entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among us, QRE GP, OLLC, the Fund, the Predecessor and QA Global.

Under the terms of the Omnibus Agreement, the Fund will offer us the first option to purchase properties that it may offer for sale, so long as the properties consist of at least 70% proved developed producing reserves. The 70% threshold is a value-weighted determination made by the Fund. Additionally, the Fund will allow us to participate in acquisition opportunities to the extent that it invests any of the remaining approximately $193.2 million of its unfunded committed equity capital. Specifically, the Fund will offer us the first opportunity to participate in at least 25% of each acquisition opportunity available to it, so long as at least 70% of the allocated value is attributable to proved developed producing reserves. In addition to opportunities to purchase proved reserves from, and to participate in future acquisition opportunities with, the Fund, if QA Global or its affiliate establishes another fund to acquire oil and natural gas properties within two years of the closing of the IPO, QA Global will cause such fund to provide us with a similar right to participate in such fund’s acquisition opportunities. These contractual obligations will remain in effect until December 21, 2015.

The Omnibus Agreement provides that the Fund will indemnify us against: (i) title defects, subject to a $75,000 per claim de minimus exception, for amounts in excess of a $4.0 million threshold, and (ii) income taxes attributable to pre-closing operations as of the Closing Date of our IPO. The Fund indemnification obligation will (i) survive for one year after the closing of our IPO with respect to title, and (ii) terminate upon the expiration of the applicable statute of limitations with respect to income taxes. We will indemnify the Fund against certain potential environmental claims, losses and expenses associated with the operation of our business that arise after the consummation of our IPO.

Management Incentive Fee

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

•

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

•

adjusted for our commodity derivative contracts; and

•

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

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

Purchase and Sale Agreement

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

Long–Term Incentive Plan

On December 22, 2010, in connection with the closing of the IPO, the Board of Directors of QRE GP adopted the Plan to compensate employees, officers, consultants and directors of QRE GP and those of its affiliates, including QRM, who perform services for us. As of December 31, 2011 and 2010, 271,364 and 148,150 restricted unit awards with a fair value of $4.8 million and $2.8 million were granted under the Plan. For additional discussion regarding the Plan see Note 11.

Distributions of available cash to our QRE GP and affiliates

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

Our relationship with Bank of America

Don Powell, one of our independent directors, is also a director of Bank of America (“BOA”). BOA is a lender under our Credit Agreement.

NOTE 15 — PREDECESSOR’S UNCONSOLIDATED INVESTMENT IN UTE ENERGY, LLC

Ute Energy, LLC (“Ute”), a Delaware limited liability company, was formed on February 2, 2005 for the purpose of developing the mineral and surface estate of the Ute Indian Tribe by participating in oil and gas exploration and development, as well as the construction and operation of gas gathering and transportation facilities. Ute’s properties are located on the Uintah and Ouray Reservation in northeastern Utah. On July 9, 2007, the Predecessor initially acquired an interest in Ute and accounts for the investment using the equity method of accounting.

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

During 2009, the Predecessor purchased additional ownership interests in Ute bringing their total ownership percentage to 25% as of December 31, 2009.

In March 2010, as part of the wider recapitalization of Ute, the Predecessor exchanged its 2,929,471 redeemable units for 2,929,471 common units and was issued an additional 175,126 redeemable units. This share-for-share exchange resulted in a gain of $4,064,000The non-cash recapitalization converted certain of the redeemable units into Class A common units at a valuation of $10 per unit with the remaining 175,126 redeemable units that will accrue a return equal to 12% per annum being retained by the Predecessor. The overall recapitalization resulted in a decrease in the Predecessor’s common unit class ownership from 25to 23.8%.

The Predecessor’s equity in earnings of Ute was $3.8 million and $2.7 millionfor the period of January 1, 2010 through December 21, 2010, and for the year ended December 31, 2009. The Predecessor’s unconsolidated investment in Ute was $41.6 million as of December 31, 2009.

The following table shows summarized financial information of the Predecessor’s investment in Ute for the periods indicated:


	January 1 to December 21, 2010			2009
Revenues	$	37,818		$	10,025
Operating expenses		(27,071	)		(14,059	)
Operating profit (loss)		10,747			(4,034	)
Interest expense		(2,192	)		(2,275	)
Other income/(expense)		7,163			4,999

Net income (loss)	$	15,718		$	(1,310	)


	December 31, 2009
Current assets	$	2,288
Net oil and gas properties		34,417
Equity method investments		94,248
Other assets		1,978

Total assets	$	132,931

Current liabilities	$	5,538
Long-term liabilities		52,010
Members’ equity		75,383

Total liabilities and members’ equity	$	132,931

NOTE 16 — SUPPLEMENTAL CASH FLOW INFORMATION

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


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

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

NOTE 17 — SUBSEQUENT EVENTS

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

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

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


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

NOTE 18 — SUBSIDIARY GUARANTORS

The Partnership anticipates filing a registration statement on Form S-3 with the SEC to register, among other securities, debt securities. The subsidiaries of the Partnership (the “Subsidiaries”) will be co-registrants with the Partnership, and the registration statement will register guarantees of debt securities by one or more of the Subsidiaries (other than QRE Finance Corporation, which may act as co-issuer of such debt securities). The Subsidiaries are 100 percent owned by the Partnership and any guarantees by the Subsidiaries will be full and unconditional. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by the Partnership, such guarantees will constitute joint and several obligations.

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Capitalized Costs

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


	Partnership
	December 31, 2011			December 31, 2010
Proved oil and natural gas properties	$	975,182		$	892,649
Unproved oil and natural gas properties		—			—

		975,182			892,649
Accumulated depreciation, depletion and amortization		(80,469	)		(2,130	)

Net capitalized costs	$	894,713		$	890,519

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

Costs Incurred

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


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

Total	$	64,027	$	83,138	$	976,396	$	56,297

Estimated Proved Reserves

Recent SEC and FASB Guidance. In December 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. The Predecessor adopted the rules effective December 31, 2009, and the rule changes, including those related to pricing and technology, are included in our and the Predecessor’s reserve estimates.

Third Party Reserves Estimate. The reserve estimates as of December 31, 2011, 2010 and 2009 presented in the table below were based on reserve reports prepared by Miller & Lents, Ltd., independent reserve engineers, using FASB and SEC rules in effect as of December 31, 2011 ,2010 and 2009.

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

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

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

We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Following is a summary of the proved developed and total proved oil and natural gas reserves attributed to our operations for the periods indicated:


	Oil (MBbl)			Natural Gas (MMcf)			NGL (MBbl)
Partnership:
Balance, December 22, 2010		—			—			—
Contribution from Predecessor (1)		25,800			242,237			1,447
Acquisition of reserves		6,532			1,538			—
Production		(49	)		(510	)		(4	)

Balance, December 31, 2010		32,283			243,265			1,443

Extensions		1,274			677			110
Revision of previous estimates		2,459			(28,463	)		6,554
Production		(1,766	)		(16,925	)		(263	)

Balance, December 31, 2011		34,250			198,554			7,844

Proved developed reserves:
December 31, 2010		19,588			178,657			1,389

December 31, 2011		21,457			142,428			6,082

Predecessor:
Proved reserves:
Balance, December 31, 2008		8,182			34,743			—
Purchases of reserves in place		262			20,169			1,327
Sale of reserves in place		(442	)		(5,981	)		—
Revisions of previous estimates		1,045			1,760			966
Production		(739	)		(5,359	)		(207	)

Balance, December 31, 2009 (2)		8,308			45,332			2,086
Purchases of reserves in place		21,890			243,835			2,592
Revisions of previous estimates		5,653			(1,050	)		244
Production		(2,172	)		(14,753	)		(282	)

Balance, December 21, 2010 (3)		33,679			273,364			4,640

Proved developed reserves:
December 31, 2009		6,721			44,879			2,037

December 21, 2010		24,313			198,160			4,411

(1)

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

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

(3)	These reserves include 31,767 MBbl, 257,843 MMcf and 4,377 MBbl of Oil, Natural Gas and NGLs attributable to an approximate 94.3% noncontrolling interest in the Predecessor as of December 21, 2010.

Purchases of Reserves in Place. The 24,482 MBbl of liquids and 243,835 MMcf of natural gas purchased in 2010, was associated with the Denbury acquisition. The 1,589 MBbl of liquids and 20,169 MMcf of natural gas purchased in 2009, was associated with the Shongaloo Properties acquisition.

Sale of Reserves in Place. In 2009, the Predecessor sold a portion of its non-core oil and gas properties in Alabama, Colorado, Louisiana, New Mexico and Texas representing approximately 8% of total production.

Revisions of Previous Estimates. In 2009, the Predecessor had net positive revisions of 2,011 MBbl of oil and 1,760 MMcf of natural gas, primarily due to higher commodity prices in 2009 as compared to the prices at the end of 2008.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural reserves, less future development, production, plugging and abandonment costs, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day of-the-month prices for the prior 12 months were $96.19/Bbl for oil and $4.12/MMbtu for natural gas as of December 31, 2011; $74.52/Bbl for oil and $4.53/MMbtu for natural gas as of December 31, 2010 and the unweighted arithmetic average first-day of-the-month prices for the prior 12 months were $61.18/Bbl for oil and $3.87/MMbtu for natural gas as of December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2011, the relevant average realized prices for oil, natural gas and NGLs were $90.89 per Bbl, $4.28 per Mcf and $49.23 per Bbl. As of December 31, 2010, the relevant average realized prices for oil, natural gas and NGLs were $85.58 per Bbl, $3.84 per Mcf and $60.42 per Bbl. As of December 31, 2009, the relevant average realized prices for oil, natural gas and NGLs were $56.46 per Bbl, $3.75 per Mcf and $33.12 per Bbl. The impact of the adoption of the FASB’s authoritative guidance on the SEC oil and gas reserve estimation final rule on our financial statements is not practicable to estimate due to the operation and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

Changes in the demand for oil and natural gas, inflation and other factors made such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of current market value of the proved reserves attributable to our reserves.

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


	Partnership						Predecessor
	December 31, 2011			December 31, 2010			December 21, 2010 (1)			December 31, 2009 (2)
Future cash inflows	$	4,349,712		$	3,617,951		$	4,019,453		$	707,028
Future production and development costs		(1,892,789	)		(1,562,104	)		(1,790,043	)		(319,391	)

Future net cash flows		2,456,923			2,055,847			2,229,410			387,637
10% annual discount for estimated timing of cash flows		(1,284,382	)		(1,059,267	)		(1,092,216	)		(170,762	)

Standardized measure of discounted future net cash flows	$	1,172,541		$	996,580		$	1,137,194		$	216,875

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

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

The above table does not include the effects of income taxes on future net revenues because during 2011, 2010 and 2009, we were not subject to federal taxation at an entity-level. Accordingly, no provision for federal tax has been provided because taxable income is passed through to the partners. State corporate income, franchise and/or gross margins taxes have not been included due to their immateriality.

The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to our proved oil and natural gas reserves for the periods indicated:


	Partnership						Predecessor
	Year Ended December 31, 2011			December 22 to December 31, 2010			January 1 to December 21, 2010			Year Ended December 31, 2009
Beginning of period	$	996,580		$	—		$	216,875		$	131,584
Contribution from Predecessor		—			912,313			—			—
Purchases of reserves in place		—			—			836,500			51,202
Sale of reserves in place		—			—			—			(10,106	)
Acquisition of reserves					88,573			—			—
Extensions		26,016			—			—			—
Revisions of previous estimates		66,579			—			77,585			33,930
Changes in future development cost, net		(50,872	)		—			(50,731	)		3,149
Development cost incurred during the year that reduce future development costs		9,598			—			1,882			1,853
Net change in prices		192,290			—			73,352			51,552
Sales, net of production costs		(169,846	)		(4,306	)		(150,403	)		(23,724	)
Changes in timing and other		2,538			—			110,446			(35,723	)
Accretion of discount		99,658			—			21,688			13,158

End of period	$	1,172,541		$	996,580		$	1,137,194		$	216,875

Predecessor share of Ute Energy, LLC

The Predecessor has an investment in Ute that is accounted for under the equity method. The following disclosures represent the Predecessor’s share of Ute reserves and oil and gas operations. Since we do not have sufficient information from Ute to present these disclosures as of December 21, 2010 and for the 355-day period then ended, these disclosures include the year-end balances and all activity for 2010.

Capitalized Costs

The following table summarizes the carrying value of our portion of Ute’s consolidated oil and gas assets as of the dates indicated:


	2010			2009
Proved properties	$	26,704		$	12,020
Less: Accumulated depreciation,depletion, amortization and impairment		(7,187	)		(3,705	)

Proved properties, net		19,517			8,315
Unproved properties		1,067			268

Total oil and gas properties, net	$	20,584		$	8,583

Costs Incurred

The following table sets forth our share of capitalized costs incurred in Ute’s property acquisition, exploration and development activities for the years indicated:


	2010		2009
Development costs	$	14,631	$	2,787
Asset retirement obligation		116		—
Acquisitions		812		—

Total costs incurred for acquisition and development activities	$	15,559	$	2,787

Estimated Proved Reserves

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


	As of December 31,
	2010						2009
	Oil (MBbl)			Gas (MMcf)			Oil (MBbl)			Gas (MMcf)
Proved reserves:
Balance, beginning of period		1,003			2,603			227			900
Recapitalization of Ute Energy, LLC		(140	)		(529	)		—			—
Extensions, discoveries and other additions		1,117			2,552			281			660
Divestiture of reserves		—			—			(1	)		(38	)
Revisions of previous estimates		(124	)		(205	)		551			1,274
Production		(123	)		(296	)		(55	)		(193	)

Balance, end of period		1,733			4,125			1,003			2,603

Proved developed reserves:
End of period		611			1,686			283			1,078

Standardized Measure of Discounted Future Net Cash Flows

For the years ended December 31, 2010 and 2009, our share of Ute’s future cash inflows are calculated by applying the current SEC 12-month average pricing of oil and gas relating to proved reserves to the year-end quantities of those reserves. For 2010, calculations were made using SEC prices of $67.87 per Bbl WTI index for oil, $3.82 per MMBtu Henry Hub index for gas and $56.40 per Bbl Mt. Belvieu index for NGLs. For 2009, calculations were made using SEC prices of $61.18 per Bbl WTI index for oil, $3.87 per MMBtu Henry Hub index for gas and $42.83 per Bbl Mt. Belvieu index for NGLs.

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


	December 31,
	2010			2009
Future cash inflows	$	132,914		$	57,291
Future production costs		(59,674	)		(23,008	)
Future development costs		(27,886	)		(15,711	)

Future net cash flows		45,354			18,572
10 percent annual discount		(18,530	)		(9,625	)

Standardized measure of discounted future net cash flows	$	26,824		$	8,947

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


	Year ended December 31,
	2010			2009
Standardized measure of discounted future net cash flows, beginning of period	$	8,947		$	3,514
Recapitalization of Ute Energy, LLC		(1,916	)		—
Sales of oil and gas, net of production costs and local taxes		(7,601	)		(1,340	)
Extensions, discoveries and improved recoveries, less related costs		16,837			2,952
Revisions of previous quantity estimates		(964	)		2,374
Net changes in prices and production costs		5,196			192
Previously estimated development costs incurred during the period		1,779			—
Changes in estimated future development costs, net		1,344			210
Development costs incurred during the year that reduce future development costs		—			106
Sales of reserves in place		—			(65	)
Change in production rates (timing) and other		2,499			653
Accretion of discount		703			351

Standardized measure of discounted future net cash flows, end of period	$	26,824		$	8,947

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

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

Quarterly financial data was as follows for the periods indicated:


	Partnership
	First Quarter (1)			Second Quarter (2)(3)		Third Quarter (4)(5)		Fourth Quarter (6)
	First Quarter (1)			Second Quarter (2)(3)		Third Quarter (4)(5)		Fourth Quarter (6)
2011
Revenues	$	62,831		$	67,880	$	64,781	$	64,376
Gross profit (7)		43,033			46,642		40,620		41,516
Operating income		16,927			18,865		11,598		11,699
Net (loss) income		(46,549	)		28,988		105,165		(26,467	)
Limited partners’ interest in net (loss) income		(29,319	)		15,915		51,878		(26,467	)
Net (loss) income per limited partner unit	$	(0.82	)	$	0.44	$	1.45	$	(0.98	)

2010
Revenues								$	6,685
Gross profit									4,330
Operating income									1,360
Net loss									(12,067	)
Limited partners’ interest in net loss									(7,092	)
Net loss per limited partner unit								$	(0.21	)

(1)

The first quarter results were impacted due to revisions from the Transferred Properties with an increase in net loss of $17.2 million comprising of increases of $32.1 million in revenues, $21.0 million in gross margin (including $8.0 million of production expense), $7.2 million in operating income, $22.8 million in unrealized losses on commodity derivatives.

(2)

The three month second quarter results were impacted due to revisions from the Transferred Properties with an increase in net income of $13.1 million comprising of increases of $36.2 million in revenues, $23.8 million in gross margin (including$9.3 million of production expense), $8.3 million in operating income, and $12.9 million in unrealized gains on commodity derivatives.

(3)

The six months ended June 30, 2011 results were impacted due to revisions from the Transferred Properties with an increase in net loss of $4.1 million comprising of increases of $68.3 million in revenues, $44.8 million in gross margin (including $17.3 million in production expense), $15.5 million in operating income, and $9.9 million in unrealized losses on commodity derivatives.

(4)

The three months third quarter results were impacted due to revisions from the Transferred Properties with an increase in net income of $53.2 million comprising of increases of $36.1 million in revenues, $22.8 million of gross margin (including $10.0 million in production expense), $6.0 million in operating income, $100.2 million in unrealized gains on derivative commodity contracts, and $42.7 million of realized losses on commodity derivatives.

(5)

The nine months ended September, 30, 2011 results were impacted due to revisions from the Transferred Properties with an increase in net income of $49.1 million comprising of increases of $104.4 million in revenues, $67.6 million in gross margin (including $27.4 million in production expense), $21.5 million in operating income, $90.3 million in unrealized gains on commodity derivatives, and $42.7 million of realized losses on commodity derivatives.

(6)	Fourth quarter 2010 results for the Partnership include results for the 10-day period from December 22 to December 31, 2010 for the IPO Assets and Transferred Properties.

(7)	Represents total revenues less productions expenses.


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

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

Attached files

QR Energy, LP Reports

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