10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2012

or

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

For the transition period from to________

Commission File Number: 001-35010

QR ENERGY, LP

(Exact name of registrant as specified in its charter)

Delaware	90-0613069
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1401 McKinney Street, Suite 2400, Houston, Texas	77010
(Address of principal executive offices)	(Zip Code)

(Registrant’s telephone number, including area code): (713) 452-2200

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   þ Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   þ Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   o Yes þ No

As of November 8, 2012, there were 16,666,667 Class C Preferred Units, 37,445,752 Common Units, 7,145,866 Subordinated Units and 41,747 General Partner Units outstanding.

TABLE OF CONTENTS
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements	4
	Consolidated Balance Sheets as of September 30, 2012 (Unaudited) and December 31, 2011	4
	Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011	5
	Unaudited Consolidated Statement of Changes in Partners' Capital for the Nine Months Ended September 30, 2012	6
	Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011	7
	Unaudited Notes to the Consolidated Financial Statements	8
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	38
Item 4.	Controls and Procedures	38
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Mine Safety Disclosure	40
Item 5.	Other Information	40
Item 6.	Exhibits	40
Signatures		41

1

CAUTIONARY STATEMENT ABOUT FORWARD–LOOKING STATEMENTS

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

· business strategies;

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

· drilling locations;

· oil and natural gas reserves;

· technology;

· realized oil, natural gas and natural gas liquids (NGLs) prices;

· production volumes;

· lease operating expenses;

· general and administrative expenses;

· future operating results; and

· plans, objectives, expectations and intentions.

All statements, other than statements of historical fact, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number of anticipated wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties some of which are beyond our control. Actual results could differ materially from those anticipated in these forward-looking statements. One should consider carefully the statements under “Risk Factors” in this report and in our Annual Report on Form 10-K for the year ended December 31, 2011 or our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012and June 30, 2012 and the other disclosures contained herein and therein, which describe known material factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

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

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

· uncertainty inherent in estimating our reserves;

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

· cash flows and liquidity;

· potential shortages of drilling and production equipment;

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

· uncertainties surrounding the success of our secondary and tertiary recovery efforts;

2

· competition in the oil and natural gas industry;

· general economic conditions, globally and in the jurisdictions in which we operate;

· legislation and governmental regulations, including climate change legislation and federal or state regulation of hydraulic fracturing;

· the risk that our hedging strategy may be ineffective or may reduce our income;

· actions of third party co-owners of interests in properties in which we also own an interest; and

· risks related to potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties.

      The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the forward-looking events and circumstances will occur. All forward-looking statements speak only as of the date of this report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

3

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

QR ENERGY, LP
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit amounts)
	September 30,		December 31,
	2012		2011
	(Unaudited)
ASSETS
Current assets:
Cash	$	25,144	$	17,433
Accounts receivable		35,302		32,263
Due from affiliates		9,319		3,734
Derivative instruments		42,482		32,683
Prepaid and other current assets		659		249
Total current assets		112,906		86,362
Noncurrent assets:
Oil and gas properties, using the full cost method of accounting
Evaluated		1,270,689		975,182
Unevaluated		9,000		-
Gross oil and natural gas properties		1,279,689		975,182
Gas processing equipment		4,110		865
Less accumulated depreciation, depletion, and amortization		(141,912)		(80,484)
Total property and equipment, net		1,141,887		895,563
Derivative instruments		81,450		70,570
Deferred taxes		-		270
Other assets		11,408		4,279
Total noncurrent assets		1,234,745		970,682
Total assets	$	1,347,651	$	1,057,044
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Current portion of asset retirement obligations	$	845	$	348
Derivative instruments		5,176		9,569
Accrued and other liabilities		60,182		50,027
Total current liabilities		66,203		59,944
Noncurrent liabilities:
Long-term debt		620,946		500,000
Derivative instruments		14,156		16,906
Asset retirement obligations		73,507		65,353
Other liabilities		6,755		-
Deferred taxes		102		-
Total noncurrent liabilities		715,466		582,259
Commitments and contingencies (see Note 11)
Partners' capital:
Class C convertible preferred unitholders (16,666,667 units issued and outstanding
as of September 30, 2012 and December 31, 2011)		369,278		358,138
General partner (41,747 and 35,729 units issued and outstanding
as of September 30, 2012 and December 31, 2011)		614		546
Public common unitholders (37,434,720 and 17,292,279 units issued
and outstanding as of September 30, 2012 and December 31, 2011)		258,578		241,306
Affiliated common unitholders (0 and 11,297,737 units issued
and outstanding as of September 30, 2012 and December 31, 2011)		-		(113,414)
Subordinated unitholders (7,145,866 units issued and outstanding
as of September 30, 2012 and December 31, 2011)		(62,488)		(71,735)
Total partners' capital		565,982		414,841
Total liabilities and partners' capital	$	1,347,651	$	1,057,044
See accompanying notes to the consolidated financial statements

4

QR ENERGY, LP
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except per unit amounts)
		Three Months Ended				Nine Months Ended
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
Revenues:
Oil and natural gas sales	$	64,559	$	64,289	$	191,722	$	193,969
Processing and other		410		492		1,243		1,523
Total revenues		64,969		64,781		192,965		195,492
Operating Expenses:
Production expenses		24,681		24,161		73,448		65,197
Depreciation, depletion and amortization		21,298		19,965		61,428		58,295
Accretion of asset retirement obligations		915		719		2,645		2,033
General and administrative		9,232		8,338		26,345		22,577
Acquisition and transaction costs		278		-		1,286		-
Total operating expenses		56,404		53,183		165,152		148,102
Operating income		8,565		11,598		27,813		47,390
Other income (expense):
Realized gains (losses) on commodity derivative contracts		13,375		(39,072)		35,668		(79,924)
Unrealized gains (losses) on commodity derivative contracts		(55,585)		153,378		12,328		160,233
Interest expense, net		(11,533)		(19,950)		(28,398)		(39,161)
Total other income (expense), net		(53,743)		94,356		19,598		41,148
Income (loss) before income taxes		(45,178)		105,954		47,411		88,538
Income tax benefit (expense), net		171		(789)		(528)		(934)
Net income (loss)	$	(45,007)	$	105,165	$	46,883	$	87,604
Net income (loss) per limited partner unit:
Common unitholders' (basic)	$	(1.25)	$	1.45	$	0.49	$	1.07
Common unitholders' (diluted)		(1.25)		1.45		0.49		1.07
Subordinated unitholders' (basic)		(1.26)		1.45		0.33		1.07
Subordinated unitholders' (diluted)		(1.26)		1.45		0.33		1.07
Weighted average number of limited partner units outstanding:
Common units (basic)		37,425		28,713		34,347		28,698
Common units (diluted)		37,425		28,713		34,347		28,698
Subordinated units (basic and diluted)		7,146		7,146		7,146		7,146
See accompanying notes to the consolidated financial statements

5

QR ENERGY, LP
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (UNAUDITED)
(In thousands)
		Class C
		Convertible				Limited Partners						Total
		Preferred		General		Public		Affiliated				Partners'
		Unitholders		Partner		Common		Common		Subordinated		Capital
Balances - December 31, 2011	$	358,138	$	546	$	241,306	$	(113,414)	$	(71,735)	$	414,841
Contributions from the Predecessor		-		-		-		4,985		17,239		22,224
Proceeds from unit offering		-		-		161,958		-		-		161,958
Units issued to the General Partner		-		115		-		-		-		115
Recognition of unit-based awards		-		-		2,125		-		-		2,125
Reduction in units to cover individuals' tax withholding		-		-		(21)		-		-		(21)
Distributions to unitholders		(10,500)		(60)		(55,100)		-		(10,362)		(76,022)
Amortization of discount on increasing rate distributions		11,140		-		-		-		-		11,140
Noncash distribution to preferred unitholders		(11,140)		-		-		-		-		(11,140)
Affiliated unit sale to public		-		-		(113,325)		113,325		-		-
Management incentive fee earned		-		(6,121)		-		-		-		(6,121)
Net income		21,640		6,134		21,635		(4,896)		2,370		46,883
Balances - September 30, 2012	$	369,278	$	614	$	258,578	$	-	$	(62,488)	$	565,982
See accompanying notes to consolidated financial statements

6

QR ENERGY, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
		Nine Months Ended
		September 30, 2012		September 30, 2011
Cash flows from operating activities:
Net income	$	46,883	$	87,604
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization		61,428		58,295
Accretion of asset retirement obligations		2,645		2,033
Recognition of unit-based awards		2,124		990
General and administrative expense contributed by affiliates		22,224		21,252
Unrealized gains on derivative contracts		(23,011)		(135,590)
Deferred income tax benefit		372		361
Other items		3,222		1,950
Changes in operating assets and liabilities:
Accounts receivable and other assets		(11,232)		(16,529)
Accounts payable and other liabilities		5,731		2,015
Net cash provided by operating activities		110,386		22,381
Cash flows from investing activities:
Additions to oil and gas properties		(80,566)		(43,917)
Proceeds from the sale of oil and gas properties		3,082		1,327
Acquisitions		(225,118)		-
Net cash used in investing activities		(302,602)		(42,590)
Cash flows from financing activities:
Proceeds from unit offering, net of offering costs		161,958		41,963
Proceeds from senior note offering, net of discount		295,860		-
Distributions to the Fund		-		(42,000)
Proceeds from issuance of units to the General Partner		115		715
Management incentive fee to the General Partner		(3,155)		-
Distributions to unitholders		(70,959)		(31,223)
Contributions from the Predecessor		-		8,985
Proceeds from bank borrowings		116,500		41,000
Repayments on bank borrowings		(291,500)		-
Deferred financing costs		(8,892)		(214)
Net cash provided by financing activities		199,927		19,226
Increase (decrease) in cash		7,711		(983)
Cash at beginning of period		17,433		2,195
Cash at end of period	$	25,144	$	1,212
See accompanying notes to the consolidated financial statements

7

QR Energy, LP

Notes toConsolidated Financial Statements (Unaudited)

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 assets of the affiliated entity, QA Holdings, LP (the “Predecessor”) and own other assets. Certain of the Predecessor’s subsidiaries (collectively known as the “Fund”) include 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. Quantum Resources Management, LLC (“QRM”) provides management and operational services for us and the Fund. Our general partner is QRE GP, LLC (or “QRE GP”). We conduct our operations through our wholly owned subsidiary QRE Operating, LLC (“OLLC”). Our wholly owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities.

We completed our initial public offering of 15,000,000 common units representing limited partner interests in the Partnership on December 22, 2010 (the “Closing Date”). 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. In exchange for the net assets, the Fund received 11,297,737 common and 7,145,866 subordinated limited partner units. QRE GP made a capital contribution to the Partnership in exchange for 35,729 general partner units.  The underwriters exercised their over-allotment option in full for 2,250,000 common units issued by the Partnership. Net proceeds from the sale of these common units, after deducting offering costs, were approximately $42 million.

On October 3, 2011, the Fund sold certain oil and gas properties to the Partnership (the “Transferred Properties”) pursuant to a purchase and sale agreement by and among the Fund, the Partnership and OLLC in exchange for 16,666,667 Class C Convertible Preferred Units (“Preferred Units”) and the assumption of $227 million in debt (the “Transaction”).  The fair value of the Preferred Units on October 1, 2011 was $21.27 per unit or $354.5 million with net assets of $252.0 million contributed to the Partnership by the Fund. The Transaction was accounted for as a transaction between entities under common control whereby the Transferred Properties were recorded at historical book value. As such, the value of the Preferred Units in excess of the net assets contributed by the Fund was deemed a $102.5 million distribution from the Partnership and allocated pro rata to the general partner and existing limited partners.

On April 17, 2012, we issued 6,202,263 common units representing limited partnership interests in us, and the Fund sold 11,297,737 of its common units it held in us (the “Equity Offering”), to the public pursuant to a registration statement filed with the Securities and Exchange Commission (the “SEC”).  In conjunction with the Equity Offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. Refer to Note 10 – Partners’ Capital for further details. Proceeds from the Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.

On April 20, 2012, we closed the acquisition of primarily oil properties from Prize Petroleum, LLC and Prize Petroleum Pipeline, LLC (collectively “Prize”) for approximately $225 million in cash(the “Prize Acquisition”), with an effective date of January 1, 2012.  Refer to Note 3 – Acquisitions for further details.

On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register the issuance and sale, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Note 16 – Subsidiary Guarantors for details.

On July 30, 2012, we and our wholly-owned subsidiary QRE FC, issued $300 million of 9.25% Senior Notes (the “Senior Notes”) due 2020.  On September 7, 2012, we filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes to exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012. The

8

exchange of the Senior Notes was completed on November 7, 2012. Refer to Note 9 – Long-Term Debt for further details.

As ofSeptember 30, 2012, our ownership structure comprised a 0.1% general partner interest held by QRE GP, a 38.8% limited partner interest held by the Fund, represented by all of our preferred and subordinated units, and a 61.1% limited partner interest held by the public unitholders.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles in the United States (“U.S. GAAP”) for complete annual financial statements. During interim periods, the Partnership follows the accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”), filed with the SEC. The unaudited consolidated financial statements for the three and nine months  ended September 30, 2012 and 2011 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. Prior period amounts have been revised to conform to current period presentation. Operating results for the three and nine months ended September 30, 2012 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2012. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our 2011 Annual Report.

The Partnership’s historical financial statements previously filed with the SEC have been revised in this quarterly report on Form 10-Q 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 January 1, 2011 to September 30, 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 set forth in Note 2 of the Notes to Consolidated Financial Statements in our 2011 Annual Report.

Accounting Policy Updates/Revisions

The accounting policies followed by the Partnership are set forth in Note 2 – Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in our 2011 Annual Report. There have been no significant changes to these policies during the nine months ended September 30, 2012 with the exception of the updates below.

Unevaluated Properties

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

9

Business Combinations

We account for all business combinations using the purchase method, in accordance with U.S. GAAP. Under the purchase method of accounting, a business combination is accounted for at the 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. The difference between the fair value of assets acquired and liabilities assumed over the cost of the entity, if any, is recorded as either goodwill or a bargain purchase gain. The Partnership has not recognized any goodwill from business combinations.

Recent Accounting Pronouncements

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). The amendments in ASU 2011-04 are the result of the FASB's and the International Accounting Standards Board's (“IASB”) work to develop common requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP 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 amendment was adopted by us on January 1, 2012 and did not 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 instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a 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

Prize Properties

On April 20, 2012 we closed the Prize Acquisition. We acquired predominantly low decline, long life oil properties, almost all of which are located in the Ark-La-Tex area, for $225 million in cash after customary purchase price adjustments. The acquired properties had estimated proved reserves as of December 31, 2011 utilizing SEC case pricingof13.3 MMBoe. The acquisition had an effective date of January 1, 2012.

The Prize Acquisition qualified as a business combination and was accounted for under the purchase method of accounting.  Effective April 20, 2012 the results of operations of the acquired Prize assets are included in our unaudited statement of operations for the three and nine months ended September 30, 2012. Accordingly, we recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. The fair value measurements of the oil and gas properties and asset retirement obligations were measured using valuation techniques and inputs that convert future cash flows to a single discounted amount.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisition closing date (in thousands):

Oil and gas properties
Evaluated	$	223,740
Unevaluated		9,000
Asset retirement obligation		(4,738)
Environmental liability		(1,891)
Other current liabilities		(993)
Net assets acquired	$	225,118

10

The above estimated fair values of assets acquired and liabilities assumed are provisional and are based on the information that was available as of the acquisition date to estimate the fair value of assets acquired and liabilities assumed. We believe that the information provides a reasonable basis for estimating the fair values of assets acquired and liabilities assumed. We expect to finalize the valuation and complete the purchase price allocation as soon as practicable but no later than oneyear from the acquisition date.

The costs associated with the Prize Acquisitionof  $1.0 million are recorded in the acquisition and transaction costs caption of the consolidated statement of operations for ninemonths ended September 30, 2012.In conjunction with the Prize Acquisition, we assumed an estimated environmental liability of $1.9 million. Refer to Note 11 – Commitments And Contingencies for further details.

Since the closing date, revenues of $8.7 million and $15.2 million and operating expenses of $3.4 million and $6.1 million related to the operation of the Prize properties are included in the consolidated statements of operationsfor the three and nine months ended September 30, 2012.  The following unaudited consolidated income statement information provideunaudited actual results for the three months ended September 30, 2012 and pro forma income statement information for the nine months endedSeptember 30, 2012 and for the three and nine months ended September 30, 2011, which assumes the Prize Acquisition had occurred on January 1, 2011. The unaudited pro forma results reflect certain adjustments related to the acquisition, such as increased depreciation and amortization expense on the assets acquired from Prize resulting from the fair value of assets acquired. The unaudited pro forma financial results may not be indicative of the results that would have occurred hadthe acquisition been completed at the beginning of the periods presented, nor are they indicative of future results of operations.

		Three Months Ended				Nine Months Ended
		(Unaudited)				(Unaudited)
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
		Actual		Pro Forma		Pro Forma		Pro Forma
Total Revenue	$	64,969	$	72,815	$	205,081	$	221,574
Operating income	$	8,565	$	14,292	$	33,314	$	58,349
Net income (loss)	$	(45,007)	$	107,530	$	51,983	$	97,577
Net income (loss) per unit:
Common unitholders' (basic)	$	(1.25)	$	1.21	$	0.54	$	1.08
Common unitholders' (diluted)	$	(1.25)	$	1.21	$	0.54	$	1.08
Subordinated units (basic)	$	(1.26)	$	1.21	$	0.53	$	1.08
Subordinated units (diluted)	$	(1.26)	$	1.21	$	0.53	$	1.08

On October 26, 2012, we entered into a purchase and sale agreement with a private seller to purchase predominantly oil and natural gas properties in the Ark-La-Tex area for approximately $215 million. Refer to Note 17 – Subsequent Events for further details.

NOTE 4 – FAIR VALUE MEASURMENTS

Our financial instruments, including cash, 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). U.S. 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 requires an entity to develop its own assumptions for the asset or liability.

11

Commodity Derivative Instruments — The fair value of the commodity derivative instruments is estimated using a combined income and market valuation methodology based upon observable forward commodity price and volatility curves. The curves are obtained from independent pricing services.  We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

Interest Rate Derivative Instruments — The fair value of the interest rate derivative instruments is estimated using a combined income and market valuation methodology based upon observable forward interest rates and volatility curves. The curves are obtained from independent pricing services. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

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 September 30, 2012 and December 31, 2011. All fair values reflected below and on the consolidated balance sheet have been adjusted for nonperformance risk.

As of September 30, 2012		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	123,932	$	-	$	123,932	$	-
	$	123,932	$	-	$	123,932	$	-
Liabilities from commodity derivative instruments	$	6,062	$	-	$	6,062	$	-
Liabilities from interest rate derivative instruments		13,270		-		13,270		-
	$	19,332	$	-	$	19,332	$	-
As of December 31, 2011		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	103,233	$	-	$	103,233	$	-
Assets from interest rate derivative instruments		20		-		20		-
	$	103,253	$	-	$	103,253	$	-
Liabilities from commodity derivative instruments	$	2,502	$	-	$	2,502	$	-
Liabilities from interest rate derivative instruments		23,973		-		23,973		-
	$	26,475	$	-	$	26,475	$	-

Fair Value of Other Financial Instruments

Fair value guidance requires certain fair value disclosures, such as those on our long-term debt, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

Revolving Credit Facility — The fair value of our long term debt depends primarily on the current active market LIBOR. The carrying value of our long term debt as of September 30, 2012 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.

Derivative Premiums – The fair value of the deferred premiums on our commodity derivatives is based on the current active market LIBOR.  The carrying value of the premiums as of September 30, 2012 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.  Refer to Note 5 – Derivative Activities for further information on the derivative premiums.

Senior Notes – The fair value of the Senior Notes is measured based on inputs from quoted, unadjusted prices from over-the-counter markets for debt instruments. If the Senior Notes had been measured at fair value, we would classify them as Level 1 under the fair value hierarchy.The fair value of the Senior Notes as of September 30, 2012 was $304.9 million.

There have been no transfers between levels within the fair value measurement hierarchy during the nine months endedSeptember 30, 2012.

12

NOTE 5 – DERIVATIVE ACTIVITIES

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 consolidated statements of operations.

Although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have presented all asset and liability positions without netting. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.  We do not post collateral under any of these contracts as they are secured under our credit facility.

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 fluctuations due to changes in the market price of oil and natural gas. We use derivatives to reduce our exposure to changes in the prices of oil and natural gas. Our policies do not permit the use of derivatives for speculative purposes.

During the nine months ended September 30, 2012, we entered into new oil swap contracts with settlement dates ranging from 2012 through 2017, natural gas put contracts, with deferred premiums, and swap contracts with settlement dates ranging from 2015 through 2017.  All of the new contracts were entered into with the same counterparties as our existing contracts.

The deferred premiums associated with certain of our oil and natural gas derivative instruments are  $4.9 million and are classified as other non-current liabilities on the consolidated balance sheet as ofSeptember 30, 2012.  There were no deferredderivative contract premiums at December 31, 2011. These deferred premiums will be paid to the counterparty with each monthly settlement (January 2015 – December 2017)  and recognized as an adjustment of realized gain (loss) on derivative instruments.

We hold commodity derivative contracts to manage our exposure to changes in the price of oil and natural gas related to our oil and natural gas production.  As of September 30, 2012, the notional volumes of our commodity derivative contracts were:

Commodity	Index		Oct 1 - Dec 31, 2012		2013		2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		5,872		6,543		5,661		4,540		2,480		3,730
Average price ($/Bbls)		$	100.34	$	99.75	$	97.91	$	96.87	$	92.07	$	87.57
Collars
Hedged Volume (Bbls/d)	WTI						425		1,025		1,500
Average floor price ($/Bbls)						$	90.00	$	90.00	$	80.00
Average ceiling price ($/Bbls)						$	106.50	$	110.00	$	102.00
Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		30,213		29,674		25,907		6,520		11,350		10,445
Average price ($/MMBtu)		$	5.89	$	6.07	$	6.23	$	5.43	$	4.27	$	4.47
Basis Swaps
Hedged Volume (MMBtu/d)	Henry Hub		20,709		18,466		17,066		14,400
Average price ($/MMBtu)		$	(0.15)	$	(0.17)	$	(0.19)	$	(0.19)
Collars
Hedged Volume (MMBtu/d)	Henry Hub		2,609		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
Puts
Hedged Volume (MMBtu/d)	Henry Hub								420		11,350		10,445
Average price ($/MMBtu)								$	4.00	$	4.00	$	4.00

13

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 LIBOR component on our outstanding variable rate debt.  The changes in the fair value of these instruments are recorded in current earnings.

On July 31, 2012, we terminated certain interest rate derivative contracts which were scheduled to expire at various times through the fourth quarter 2015 and recorded a $15 million realized loss for the early termination.

The fair value of our derivatives as recorded on our balance sheet was as follows as of the dates indicated:

		September 30, 2012				December 31, 2011
		Asset		Liability		Asset		Liability
		Derivatives		Derivatives		Derivatives		Derivatives
Commodity contracts	$	123,932	$	6,062	$	103,233	$	2,502
Interest rate contracts		-		13,270		20		23,973
	$	123,932	$	19,332	$	103,253	$	26,475
Commodity
Current	$	42,482	$	565	$	32,683	$	1,284
Noncurrent		81,450		5,497		70,550		1,218
	$	123,932	$	6,062	$	103,233	$	2,502
Interest
Current	$	-	$	4,611	$	-	$	8,285
Noncurrent		-		8,659		20		15,688
	$	-	$	13,270	$	20	$	23,973
Total Derivatives
Current	$	42,482	$	5,176	$	32,683	$	9,569
Noncurrent		81,450		14,156		70,570		16,906
	$	123,932	$	19,332	$	103,253	$	26,475

The following table presents the impact of derivatives and their location within our unaudited consolidated statements of operations for the three andninemonths ended September 30, 2012 and September 30, 2011:

		Three Months Ended				Nine Months Ended
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
Realized gains (losses):
Commodity contracts (1)	$	13,375	$	(39,072)	$	35,668	$	(79,924)
Interest rate swaps (2)		(16,145)		(969)		(20,775)		(2,231)
Total	$	(2,770)	$	(40,041)	$	14,893	$	(82,155)
Unrealized gains (losses):
Commodity contracts (1)	$	(55,585)	$	153,378	$	12,328	$	160,233
Interest rate swaps (2)		12,973		(14,596)		10,683		(24,643)
Total	$	(42,612)	$	138,782	$	23,011	$	135,590
Total gains (losses):
Commodity contracts (1)	$	(42,210)	$	114,306	$	47,996	$	80,309
Interest rate swaps (2)		(3,172)		(15,565)		(10,092)		(26,874)
Total	$	(45,382)	$	98,741	$	37,904	$	53,435

⁽¹⁾ Gain (loss) on commodity derivative contracts is located in other income (expense) in the consolidated statements of operations.

⁽²⁾ Gain (loss) on interest rate derivatives contracts is recorded as part of interest expense and is located in other income (expense) in the consolidated statements of operations.

14

NOTE 6 – INCOME TAXES

We do not pay federal income taxes as our profits or losses are reported to the taxing authorities by the individual partners.

Our income taxes are entirely attributable to the Texas Margin Tax which is derived from our taxable income apportioned to Texas. We recorded a deferred tax asset of $0.3 million and$0.3 million related to its operations located in Texas as of September 30, 2012 and December 31, 2011 and a deferred tax liability of $0.4 million and less than $0.1 million as of September 30, 2012 and December 31, 2011. The deferred tax asset and deferred tax liability are presented net as a deferred tax liability of $0.1 million on the consolidated balance sheet as of September 30, 2012 and as a deferred tax asset of $0.3 million on the consolidated balance sheet as of December 31, 2011. Our provision for income taxes was a net benefit of $0.2 million and a net expense of  $0.5 million for the three and nine months ended September 30, 2012 and a net expense of $0.8 million and $0.9 million for the three and nine months ended September 30, 2011.

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

We record the asset retirement obligation (“ARO”) liability on our unaudited consolidated balance sheet and capitalize the cost in the “Oil and gas properties, using the full cost method of accounting” balance sheet caption during the period in which the obligation is incurred. We record the accretion of our ARO liabilities in “Accretion of asset retirement obligations” expense in our unaudited consolidated statements of operations. Payments to settle asset retirement obligations occur over the lives of the oil and gas properties. Revisions during the reporting period were due to changes in cost estimates for wells currently being retired.

Changes in our asset retirement obligations for ninemonths ended September 30, 2012 are presented in the following table:

		Nine Months Ended
		September 30, 2012
Beginning of period	$	65,701
Assumed in acquisition		4,738
Divested		(23)
Revisions to previous estimates		2,928
Liabilities incurred		1,208
Liabilities settled		(2,845)
Accretion expense		2,645
End of period	$	74,352
Less: Current portion of asset retirement obligations		(845)
Asset retirement obligations - non-current	$	73,507

NOTE 8 – ACCRUED AND OTHER LIABILITIES

As of September 30, 2012 and December 31, 2011, we had the following accrued and other liabilities:

		September 30, 2012		December 31, 2011
Distributions payable	$	25,628	$	20,545
Accrued capital spending		2,931		9,591
Production expense accrual		16,925		12,872
Senior notes interest accrual		4,625		-
Management incentive fee		4,538		1,572
Other		5,535		5,447
	$	60,182	$	50,027

15

NOTE 9 – LONG-TERM DEBT

As ofSeptember 30, 2012 and December 31, 2011, long-term consisted of (in thousands):

		September 30, 2012		December 31, 2011
Senior revolving credit facility	$	325,000	$	500,000
9.25% Senior Notes due 2020 (1)		295,946		-
Total long-term debt	$	620,946	$	500,000

⁽¹⁾ The amount is net of unamortized discount of $4.1 million as of September 30, 2012.

Revolving Credit Facility

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

We entered into a Second Amendment to the Credit Agreement on March 16, 2012 to provide for additional derivative contracts to cover production of proved reserves to be acquired.

In April 2012, we entered into the Third Amendment to the Credit Agreement whereby increasing our credit facility from $750 million to $1.5 billion, increasing our borrowing base from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017. The Third Amendment became effective upon the closing of the Prize Acquisition.

As a result of the issuance of the Senior Notes on July 30, 2012, our borrowing base was reduced by $75 million to $655 million from $730 million. On the same date, we made a payment on our outstanding borrowings under our revolving credit facility of $291.5 million using the cash proceeds from the Senior Notes issuance and cash on hand.  In connection with the reduction of the borrowing base, we wrote-off approximately $0.7 million of deferred loan costs associated with the Credit Agreement. On October 30, 2012, we were notified of an increase in our borrowing base, as part of our semi-annual borrowing base redetermination, from $655 million to the borrowing base prior to the issuance of the Senior Notes of$730 million.

As of September 30, 2012, we had $325.0 million of borrowings outstanding and $0.1 million of letters of credit outstanding resulting in $329.9 million of borrowing availability. As of December 31, 2011, we had $500.0 million of borrowings and $0.4 million letters of credit outstanding resulting in $129.6 million of borrowing availability.

As of November 8, 2012 we had $325.0 million of borrowings outstanding under our revolving credit facility and $404.9 million of borrowing availability.

As of September 30, 2012, the Credit Agreement provides for a five-year, $1.5 billion revolving credit facility maturing on April 20, 2017, with a borrowing base of approximately $655 million. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ pricing assumptions, and other various factors unique to each member bank.The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. 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%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% 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 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum.

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 our 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 also requires us to provide audited financial statements within 90 days of year end and quarterly unaudited

16

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 our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reservesthereafter, 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 September 30, 2012, we were in compliance with all of the Credit Agreement covenants.

Bridge Loan Commitment

In conjunction with the Prize Acquisition, we entered into a secured commitment (the “Bridge Loan Commitment”) to provide an additional $200 million of bank loans to fund the acquisition as needed. We did not utilize any borrowings under the commitment and as of May 10, 2012 the Bridge Loan Commitment was terminated by us. We incurred $1.6 million of commitment fees related to the Bridge Loan Commitment which is recorded in interest expense for the nine months ended September 30, 2012.

9.25% Senior Notes

On July 30, 2012, we and our wholly-owned subsidiary QRE FC, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 9.25% Senior Notes, due 2020. The Senior Notes were issued at 98.62% of par. We received approximately $291.2 million of cash proceeds, net of the discount and underwriting fees, with total net proceeds of approximately  $290.2 million, after $1.0 million ofoffering costs. We used the net proceeds from the sale of the Senior Notes to repay borrowings outstanding under our credit facility. We will have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Our and QRE FC’s obligations under the Senior Notes are guaranteed by OLLC. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor’s, other, debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Note 16 – Subsidiary Guarantors for further details of our guarantors.

The indenture governing the Senior Notes (the “Indenture”) restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale-leaseback transactions; (ii) pay distributions on, or repurchase, equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.  The Indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the Senior Notes.

On September 7, 2012, we filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes to exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012. The exchange offer was completed on November 7, 2012.

17

NOTE 10 — PARTNERS’ CAPITAL

Units Outstanding

The table below details the units outstanding as of September 30, 2012 and December 31, 2011, and the changes in outstanding units for the nine months ended September 30, 2012.  As of September 30, 2012, the Fund owned all preferred units and all subordinated units.

	Preferred Units	General Partner	Public Common	Affiliated Common	Subordinated
Balance - December 31, 2011	16,666,667	35,729	17,292,279	11,297,737	7,145,866
Vested units awarded under our Long Term Incentive
Performance Plan	-	-	18,359	-	-
Reduction in units to cover individuals' tax withholdings	-	-	(918)	-	-
Issuance of units to General Partner	-	6,018	-	-	-
Affiliated unit sale to the public	-	-	11,297,737	(11,297,737)	-
Unit offering	-	-	8,827,263	-	-
Balance - September 30, 2012	16,666,667	41,747	37,434,720	-	7,145,866

On April 17, 2012, we issued6,202,263 common units representing limited partnership interests in us, and the Fund sold11,297,737of its common units it held in us to the public pursuant to a registration statement filed with the SEC.  In conjunction with the Equity Offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. Proceeds from the Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.

On April 25, 2012, QRE GP purchased 6,018 general partner units in order to maintain its0.1% ownership percentage in us. The units were purchased at a price of $19.18 per unit.

On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Note 16 – Subsidiary Guarantors for details

Allocations of Net Income (Loss)

Net income (loss) is allocated to the preferred unitholders to the extent distributions are made or accrued to them during the period,  to QRE GP to the extent of the management incentive fee, 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 Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in our Credit Agreement, occurs or would result from the cash distribution.

Our partnership agreement, as amended, 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.

As of September 30, 2012, QRE GP owns a 0.1% general partner interest in us, represented by 41,747 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 0.1% interest in these distributions will be reduced if we

18

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.

Distribution activities are as follows:

						Limited Partners
							Affiliated
Payment Date	For the period ended	Distributions to Preferred Unitholders		Distributions per Preferred Unit(1)	General Partner	Public Common	Common	Subordinated	Total Distributions to Other Unitholders	Distributions per other units
(In thousands, except per unit amounts)
February 10, 2012	December 31, 2011	3,424	$	0.2054	16	8,344	5,368	3,393	17,121	0.4750
May 11, 2012	March 31, 2012	3,500	$	0.21	20	17,892	-	3,394	21,306	0.4750
August 10, 2012	June 30, 2012	3,500	$	0.21	20	18,584	-	3,484	22,088	0.4875
November 9, 2012	September 30, 2012	3,500	$	0.21	20	18,624	-	3,484	22,128	0.4875

(1) Preferred units paid in February 2012 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.

On September 28, 2012, the board of directors of QRE GP declared a $0.4875 per unit cash distribution for the third quarter 2012 whichis payable on November 9, 2012 to unitholders of record at the close of business on October 29, 2012.  The aggregate amount of the third quarter common and preferred unit holder distribution accrued, as of September 30, 2012,  was $25.6 million.

NOTE11–COMMITMENTSANDCONTINGENCIES

Services Agreement

We have entered into a services agreement (the “Services Agreement”) with QRM as described in Note 14 – Related Party Transactions, under which QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined under the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee.  The Partnership had no other commitments as of September 30, 2012.

Legal Proceedings

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. 

Environmental Contingencies

As of September 30, 2012, we have approximately $1.9 million in environmental liabilities related to the Prize Acquisition. This is management’s best estimate of the costs for remediation and restoration with respect to these environmental matters, although the ultimate cost could increase materially. The environmental liability is recorded in the other liabilities caption on the consolidated balance sheet. Inherent uncertainties exist in these estimates primarily due to unknown conditions, changing governmental regulation and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration.

19

NOTE 12 – NET INCOME/(LOSS) PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income (loss) per limited partner unit for the three and nine months ended September 30, 2012 and September 30, 2011:

		Three Months Ended				Nine Months Ended
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
Net income (loss)	$	(45,007)	$	105,165	$	46,883	$	87,604
Net income (loss) attributable to predecessor operations		-		(53,235)		-		(49,091)
Distribution on Class C convertible preferred units		(3,500)		-		(10,500)		-
Amortization of preferred unit discount		(3,751)		-		(11,140)		-
Net income (loss) available to other unitholders		(52,258)		51,930		25,243		38,513
Less: general partner's interest in net income (loss)		3,705		52		6,150		39
Limited partners' interest in net income (loss)	$	(55,963)	$	51,878	$	19,093	$	38,474
Common unitholders' interest in net income (loss)	$	(46,930)	$	41,540	$	16,717	$	30,829
Subordinated unitholders' interest in net income (loss)	$	(9,033)	$	10,338	$	2,376	$	7,644
Net loss per limited partner unit:
Common unitholders' (basic)	$	(1.25)	$	1.45	$	0.49	$	1.07
Common unitholders' (diluted)		(1.25)		1.45		0.49		1.07
Subordinated unitholders' (basic)	$	(1.26)	$	1.45	$	0.33	$	1.07
Subordinated unitholders' (diluted)		(1.26)		1.45		0.33		1.07
Weighted average number of limited partner units outstanding (1):
Common units (basic)		37,425		28,713		34,347		28,698
Common units (diluted)		37,425		28,713		34,347		28,698
Subordinated units (basic and diluted)		7,146		7,146		7,146		7,146

⁽¹⁾ For the three and nine months ended September 30, 2012, we had weighted average preferred units outstanding of 16,666,667, which are contingently convertible.  These units could potentially dilute earnings per unit in the future and have not been included in the earnings per unit calculation for the three and nine months ended September 30, 2012, as they were anti-dilutive for the periods.

Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the limited partner unitholders, after deducting QRE GP’s 0.1% interest in net income (loss), by the weighted average number of limited partner units outstanding during the three and nine months ended September 30, 2012. We had 37,434,720 common units and 7,145,866 subordinated units outstanding as of September 30, 2012.

NOTE 13 – UNIT-BASED COMPENSATION

The QRE GP, LLC Long-Term Incentive Plan (the “Plan”) was established for employees, officers, consultants and directors and consultants of QRE GP and 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 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.

Restricted Units

During 2012, we issued restricted stock units with a service condition (“Restricted Units”) and restricted units with a performance condition (“Performance Units”). The fair value of the restricted units is based on the closing price of our common units at the grant date.

Service Restricted Units

For Restricted Units, we recognize compensation expense using a straight-line amortization of the grant date fair value over the vesting period of the award. On July 25, 2012, we granted an additional 392,149 Restricted Units to employees of QRM with a grant date per unit value of $18.19. For the three and nine months ended September 30, 2012, we recognized compensation expense related to the outstanding awards of $1.4 million and $2.2 million. For the three and nine months ended September 30, 2011 we recognized compensation expense of $0.4 million and $1.0 million. As of September 30, 2012, we had 645,563 of Restricted Units outstanding with unrecognized grant

20

date fair value compensation expense of $11.9 million, which we expect to be recognized over a weighted-average period of approximately 3 years.

Performance Restricted Units.

In July 2012, we granted a target number of performance shares under a performance unit award agreement to members of our senior management. The performance awards will be earned over a three year period based on the Partnership’s performance relative to its peers, with details to be determined and approved by our board in accordance with the Plan.

At each reporting period, we will assess the probability of meeting the performance conditions to determine the final units to be issued for each Performance Unit and estimate compensation expense based on this probability. For the three and nine months ended September 30, 2012, we recognized compensation expense related to the Performance Units on a straight-line method within the Restricted Units until the performance conditions are approved. There were no Performance Units outstanding in 2011.

The following table summarizes our restricted unit-based awards for nine months endedSeptember 30, 2012:

		Weighted			Weighted
		Average			Average
	Number of	Grant-Date		Number of	Grant-Date
	Service Restricted units	Fair Value		Performance units	Fair Value
Unvested units, December 31, 2011	271	$	20.33	-	$	-
Granted	428		18.18	121		18.06
Forfeited	(35)		20.23	-		-
Vested	(18)		20.16	-		-
Unvested units, September 30, 2012	646	$	18.80	121	$	18.06

Note 14 – RELATED PARTY TRANSACTIONS

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

As of September 30, 2012, affiliates of the Fund owned 100% of QRE GP, an aggregate38.8% limited partner interest in us represented by all of our preferred and subordinated units. In addition, QRE GP owned a 0.1% general partner interest in us, represented by 41,747 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 the activity of those agreements.

Services Agreement

Under the Services Agreement, until December 31, 2012, QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined under the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee. For the three and nine months ended September 30, 2012 we were charged $1.8 million and $5.4 million and for the three and nine months ended September 30, 2011, we were charged$0.7 million and  $0.8 million in administrative services fees in accordance with the Services Agreement.We will reimburse QRE GP for such payments it makes to QRM.

Beginning on January 1, 2013, QRM will be entitled to a quarterly administrative services fee based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. The fee will include direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If the Fund raises a second fund, the quarterly administrative services costs will be further divided to include the second fund as well. The allocation methodology was developed with the assistance of a third-party consultant with extensive experience in this area. These fees will be included in general and administrative expenses in our consolidated statement of operations. QRM will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.

21

 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 receivable balances during nine months endedSeptember 30, 2012 from the year ended December 31, 2011 are included below:

Net affiliate receivable as of December 31, 2011		3,734
Revenues and other increases		187,036
Expenditures		(155,351)
Settlements from the Fund		(26,100)
Net affiliate receivable as of September 30, 2012	$	9,319

Other Contributions to Partners’ Capital

Other contributions to partners’ capital for the ninemonths ended September 30, 2012 include non-cash general and administrative expense of $22.2 million contributed by the Fund, which represents our share of allocable general and administrative expenses incurred by QRM on our behalf but not reimbursable by us.

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 nine months ended September 30, 2012, the management incentive fee earned by QRE GP was $6.1 million.  For the nine months ended September 30, 2011, no management incentive fee was earned by or paid to our general partner.

Lease Guarantees

The Fund has entered into various lease contracts that can routinely extend beyond five years which list the Partnership as a guarantor. 

Long–Term Incentive Plan

The Plan provides compensation to employees, officers, consultants and directors of QRE GP and those of its affiliates, including QRM, who perform services for us. As of September 30, 2012 and December 31, 2011,  766,700 and 271,364restricted units with a grant date fair value of $14.4 million and $5.5 million were outstanding under the Plan. For additional discussion regarding the Plan see Note 13 – Unit-Based Compensation.

Distributions of Available Cash to QRE GP and Affiliates

We generally make cash distributions to our common and subordinated unitholders pro rata, including QRE GP and its affiliates. The Partnership paid a cash distribution on May 11, 2012 and August 31, 2012 for the quarters ended March 31, 2012 and June 30, 2012 and declared a third quarter 2012 distribution payable on November9, 2012.  Refer to Note 10 – Partners’ Capital for details on the distributions.

22

Our Relationship with Bank of America

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

NOTE 15 – SUPPLEMENTAL CASH FLOW INFORMATION

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

		Nine Months Ended
		September 30, 2012		September 30, 2011
Supplemental Cash Flow Information
Cash paid during the period for interest	$	33,322	$	13,236
Non-cash Investing and Financing Activities
Change in accrued capital expenditures		(6,660)		2,165
Interest rate swaps novated from the Fund		-		2,875
General and administrative expense allocated from the Fund		22,224		21,252
Amortization of increasing rate distributions(1)		11,140		-

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

NOTE 16–SUBSIDIARYGUARANTORS

On June 1, 2012,wefiled a registration statement on Form S-3 with the SEC to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC.The Partnership’s Senior Notes, issued on July 30, 2012, are guaranteed by OLLC, a 100% owned subsidiary of the Partnership, and certain other future subsidiaries (the “Guarantor”, together with any future 100% owned subsidiaries that guarantee the Partnership’s Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned by the Partnership and the guarantees by the Subsidiaries are 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. The guarantees constitute joint and several obligations. Refer to Note 9 – Long-Term Debt for details on the conditions of guarantor releases.

NOTE 17 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after September 30, 2012,  through the issuance of the financial statements.

Revolving Credit Facility Redetermination

On October 30, 2012, we completed our semi-annual borrowing base redetermination which resulted in an increase in the borrowing base of our revolving credit facility from $655 million to $730 million. Refer to Note 9 – Long-Term Debt for further details.

Acquisition of Oil and Gas Properties

On October 26, 2012, we entered into a purchase and sale agreement with a private seller to purchase predominately oil and natural gas properties in the Ark-La-Tex area for approximately $215 million. The acquisition is expected to close in the fourth quarter of 2012.

23

Derivative Contracts

In October 2012, we entered into new oil and natural gas derivative contracts for the years 2013 through 2017. These contracts were entered into with the same counterparties as our existing derivative contracts. The table below details the newly executed contracts.

Commodity	Index		2013		2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		627		1,000		931		868		817
Average price ($/Bbls)		$	88.20	$	87.53	$	85.65	$	84.65	$	84.35
Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		767		715		671
Average price ($/MMBtu)		$	3.99	$	4.27	$	4.43
Collars
Hedged Volume (MMBtu/d)	Henry Hub								630		595
Average floor price ($/MMBtu)								$	4.00	$	4.00
Average ceiling price ($/MMBtu)								$	5.55	$	6.15

Cost Allocation Methodology

On November 6, 2012, QRE GP approved a methodology for allocating general and administrative costs incurred by QRM on behalf of the Partnership upon the expiration of the current Services Agreement on December 31, 2012. Refer to Note 14 – Related Party Transactions for further details.

Completion of Senior Notes Exchange Offer

On November 7, 2012, the exchange offer for the Senior Notes, pursuant to a Form S-4 filed with the SEC, was completed. Refer to Note 9 – Long-term Debt for details.

24

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our 2011 Annual Report and the consolidated financial statements and related notes therein. Our Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations. You should also read the following discussion and analysis together with the risk factors set forth in the 2011 Annual Report and in Part I—Item 1A “Risk Factors” of this report and the “Cautionary Statement Regarding Forward-Looking Information” in this report and in our Annual Report.

Overview

QR Energy, LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed on September 20, 2010, to receive certain assets of the affiliated entity, QA Holdings, LP (the “Predecessor”) and own other assets. Certain of the Predecessor’s subsidiaries (collectively known as the “Fund”) include 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. Quantum Resources Management, LLC (“QRM”) provides management and operational services for us and the Fund. Our general partner is QRE GP, LLC (or “QRE GP”). We conduct our operations through our wholly owned subsidiary QRE Operating, LLC (“OLLC”). Our wholly owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of being a co-issuer of our debt securities.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploitation activities or acquire properties with existing production. The amount we realize for our production depends predominately upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differential and other factors. These risk factors are mitigated by our hedging program which generally hedges approximately 65% to 85% of our current and anticipated production over the next three-to-five year period. Oil and natural gas prices have been extremely volatile, and we expect this volatility to continue.  Oil and natural gas prices have experienced a general decline since 2011. The unweighted arithmetic average first day of-the-month prices for the prior 12 months decreased to $94.97/Bbl for oil and $2.83/MMbtu for natural gas as ofSeptember 30, 2012 from $96.19/Bbl for oil and $4.12/MMbtu for natural gas as of December 31, 2011. Further declines in future oil and natural gas market prices could have a negative impact on our reserve value and could result in an impairment of our oil and gas properties. For example, a hypothetical $10/Bbl decrease in the 12 month average of oil prices would decrease our reserves by $208.1 million, and a hypothetical $1/Mcf decrease in the 12 month average of natural gas prices would decrease our reserves by $104.9 million. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Results of Operations

Because affiliates of the Fund own 100% of our general partner and an aggregate 38.8% limited partner interest in us including all of our preferred and subordinated units as of September 30, 2012, each acquisition of assets from the Predecessor is considered a transfer of net assets between entities under common control. As a result, we are required to revise our financial statements to include the activities of all assets acquired from the Predecessor for all periods presented by the Partnership, similar to a pooling of interests, to include the financial position, results of operations, and cash flows of the assets acquired and liabilities assumed.  The table set forth below includes the recast historical financial information for the three and nine months ended September 30, 2011 as if the oil and gas properties acquired from the Predecessor in October 2011 were owned by us for all periods presented for the Partnership.  These results are presented for illustrative purposes only and 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.

25

Results of Operations - Continued

		Three Months Ended				Nine Months Ended
		September 30, 2012		September 30, 2011 (1)		September 30, 2012		September 30, 2011 (1)
Revenues: (2)
Oil sales	$	51,076	$	38,315	$	145,270	$	120,565
Natural gas sales		8,623		17,453		27,604		50,474
NGLs sales		4,860		8,521		18,848		22,930
Processing and other		410		492		1,243		1,523
Total Revenue		64,969		64,781		192,965		195,492
Operating Expenses:
Lease operating expenses		19,203		18,672		56,861		48,802
Production and other taxes		4,693		4,480		14,224		13,431
Processing and transportation		785		1,009		2,363		2,964
Total production expenses		24,681		24,161		73,448		65,197
Depreciation, depletion and amortization		21,298		19,965		61,428		58,295
Accretion of asset retirement obligations		915		719		2,645		2,033
General and administrative and other		9,232		8,338		26,345		22,577
Acquisition and transaction costs		278		-		1,286		-
Total operating expenses		56,404		53,183		165,152		148,102
Operating income		8,565		11,598		27,813		47,390
Other income (expense):
Realized gains (losses) on commodity derivative contracts		13,375		(39,072)		35,668		(79,924)
Unrealized gains (losses) on commodity derivative contracts		(55,585)		153,378		12,328		160,233
Interest expense, net		(11,533)		(19,950)		(28,398)		(39,161)
Total other income (expense), net		(53,743)		94,356		19,598		41,148
Income (loss) before income taxes		(45,178)		105,954		47,411		88,538
Income tax benefit (expense)		171		(789)		(528)		(934)
Net income (loss)	$	(45,007)	$	105,165	$	46,883	$	87,604
Production data (3):
Oil (MBbls)		576		439		1,575		1,314
Natural gas (MMcf)		3,400		3,834		10,587		11,709
Natural gas liquids (MBbls)		202		200		559		576
Total (Mboe)		1,345		1,278		3,899		3,842
Average Net Production (Boe/d)		14,620		13,891		14,230		14,073
Average sales price per unit (4):
Oil (Per Bbl)	$	88.67	$	87.28	$	92.23	$	91.75
Natural gas (per Mcf)	$	2.60	$	4.71	$	2.67	$	4.45
Natural gas liquids (Per Bbl)	$	29.10	$	54.27	$	41.42	$	51.07
Average unit cost per Boe:
Lease operating expense	$	14.28	$	14.61	$	14.58	$	12.70
Production and other taxes	$	3.49	$	3.51	$	3.65	$	3.50
Depreciation, depletion and amortization	$	15.83	$	15.62	$	15.75	$	15.17
General and administrative expenses	$	6.86	$	6.52	$	6.76	$	5.88

(1) These results of operations have been recast to include financial information for the assets acquired under common control.  Refer to Note 2 – Significant Accounting Policies of Notes to Financial Statements (Unaudited) for basis of presentation.

(2) Certain natural gas liquid sales for the three and nine months ended September 30, 2011 have been reclassified from natural gas sales to conform to current presentation. This resulted in an increase in natural gas liquid sales and a decrease in natural gas sales of $5.6million and $15.5 million and an increase in natural gas liquid volumes of 103 MBbls and 304 MBbls and a decrease in natural gas volumes of 615 MMcf and 1,819 MMcf.

(3) Includes certain volumes for natural gas (79 MMcf and 256 MMcf for the three and nine months endedSeptember 30, 2012 and 130 MMcf and366 MMcf for the three and nine months ended September 30, 2011) and natural gas liquids (35 MBbls and 104 Bbls for the three and nine months endedSeptember 30, 2012 and 43 MBbls and 127 MBbls for the three and nine months endedSeptember 30, 2011) for which revenues were reported on a net basis.

(4) Does not include the impact of derivative instruments.

26

Results of Operations - Continued

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

We recorded net loss of $45.0 million for the three months ended September 30, 2012 compared to net income of $105.2 million for the three months ended September 30, 2011. This change was primarily driven by a net decrease in realized and unrealized gains on commodity derivative contracts of $156.5 million.

Oil and Gas Revenues:

		Three Months Ended September 30,
						Increase	Percentage
		2012		2011		(Decrease)	Change
Production:
Oil (MBbls)		576		439		137	31%
Natural Gas (MMcf)		3,400		3,834		(434)	-11%
NGL (MBbl)		202		200		2	1%
Total (Mboe)		1,345		1,278		67	5%
Average sales prices per unit:
Oil (per Bbl)	$	88.67	$	87.28	$	1.39	2%
Natural Gas (per Mcf)		2.60		4.71		(2.11)	-45%
NGL (per Bbl)		29.10		54.27		(25.17)	-46%
Total (per Boe)		48.00		50.30		(2.30)	-5%
Revenues:
Oil sales	$	51,076	$	38,315	$	12,761	33%
Natural Gas sales		8,623		17,453		(8,830)	-51%
NGL sales		4,860		8,521		(3,661)	-43%
Total oil and gas revenue	$	64,559	$	64,289	$	270	0%

Total oil and gas revenue increased by $0.3 million to $64.6 million for the three months ended September 30, 2012 due higher production volumes despite a decrease in the prices per Boe mainly attributable to lower natural gas and NGL prices. The increase in production volumes is mainly attributable to increased oil production related to the assets acquired in the Prize Acquisition, offset by a decrease in natural gas and natural gas liquids production volumes due to the effects of natural declines in the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.

Production Expenses. Our production expense for the three months ended September 30, 2012 increased to $24.7 million from $24.2 million for the three months ended September 30, 2011, consisting mainly of an increase in lease operating expenses to $19.2 million, or $14.28 per Boe, for the three months ended September 30, 2012 from $18.7 million, or $14.61 per Boe for the three months ended September 30, 2011, and an increase in production and other taxes to $4.7 million, or $3.49 per Boe, from $4.5 million, or $3.51 per Boe for the three months ended September 30, 2011. The increase in production expenses is primarily attributable to the Prize Acquisition offset by adecrease in workover expenses in the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.  

Depreciation, Depletion and Amortization Expenses. For the three months ended September 30, 2012, our depreciation, depletion and amortization (“DD&A”) expenses were $21.3 million, or $15.83 per Boe, as compared to $20.0 million, or $15.62 per Boe, for the three months ended September 30, 2011.  The increase in DD&A expense is mainly attributable to the Prize Acquisition for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.  

General and Administrative and Other Expenses. For the three months ended September 30, 2012 our general and administrative and other expenses increased to $9.2 million, or $6.86 per Boe, as compared to $8.3 million, or $6.52 per Boe, for the three months ended September 30, 2011.  The increase is mainly attributable to the higher personnel costs associated with increasing our staffing levels to meet our current organizational needs in the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. 

27

Effects of Commodity Derivative Contracts. For the three months ended September 30, 2012, our realized gains on commodity derivative contracts increased to $13.4 million from a realized loss of $39.1 million for the three months ended September 30, 2011.Unrealized gains (losses) on commodity derivative contracts decreased to a  $55.6 million loss for the three months September 30, 2012 from a  $153.4 million gain for the three months ended September 30, 2011.  Unrealized gains and losses result from changes in the future commodity prices as compared to the fixed price of our open commodity derivative contracts. Realized gains and losses result from the settlement of derivative contracts at the market price as compared to the fixed contract price.

The change in realized and unrealized gains (losses) is mainly attributable to increasing oil and gas prices as compared to our fixed price derivative contracts in the three months ended September 30, 2012 as compared to decreasing oil and gas prices in the threemonths ended September 30, 2011, as well as the modification of certain oil derivative contracts during the third quarter of 2011. 

Interest Expense, net. Net interest expense decreased to $11.5 million for the three months ended September 30, 2012 as compared to $20.0 million for the three months ended September 30, 2011.  The net decrease in realized and unrealized losses on derivative contracts is related to lower interest rates in September 30, 2012 versus September 30, 2011 offset by an increase in interest expense of $4.1 million related to the Senior Notes issued during the three months ended September 30, 2012.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

We recorded net income of $46.9 million for thenine months ended September 30, 2012 compared to net income of $87.6 million for the nine months ended September 30, 2011. This change was primarily driven by a net decrease in realized and unrealized gains on commodity derivative contracts of $32.3 million and an increase in lease operating expenses of $8.1 million.

Oil and Gas Revenues:

		Nine Months Ended September 30,
						Increase	Percentage
		2012		2011		(Decrease)	Change
Production:
Oil (MBbls)		1,575		1,314		261	20%
Natural Gas (MMcf)		10,587		11,709		(1,122)	-10%
NGL (MBbl)		559		576		(17)	-3%
Total (Mboe)		3,899		3,842		57	1%
Average sales prices per unit:
Oil (per Bbl)	$	92.23	$	91.75	$	0.48	1%
Natural Gas (per Mcf)		2.67		4.45		(1.78)	-40%
NGL (per Bbl)		41.42		51.07		(9.65)	-19%
Total (per Boe)		49.17		50.49		(1.32)	-3%
Revenues:
Oil sales	$	145,270	$	120,565	$	24,705	20%
Natural Gas sales		27,604		50,474		(22,870)	-45%
NGL sales		18,848		22,930		(4,082)	-18%
Total oil and gas revenue	$	191,722	$	193,969	$	(2,247)	-1%

Total oil and gas revenue decreased by $2.2 million to $191.7 million for the nine months ended September 30, 2012due to lower sales prices per Boe mainly attributed to decreased prices for natural gas and natural gas liquids, partially offset by a slight increase in the total production volumes of 57 Mboe.The increase in production volumes is mainly attributable to increased oil production related to the assets acquired in the Prize Acquisition, offset by a decrease in natural gas and natural gas liquids production volumes due to the effects of natural declines in the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.

Production Expenses. Our production expense for the nine months ended September 30, 2012 increased to $73.4 million from $65.2 million for nine months ended September 30, 2011, consisting mainly of an increase in lease operating expenses to $56.9 million, or $14.58 per Boe, for the nine months ended September 30, 2012 from $48.8 million, or $12.70 per Boe for the nine months ended September 30, 2011, and an increase in production and

28

other taxes to $14.2 million, or $3.65 per Boe, from $13.4 million, or $3.50 per Boe for the nine months ended September 30, 2011. The increase in production expenses is attributable to the Prize Acquisition, an increase in workover expenses, and an increase in other lease operating expenses in the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.

Depreciation, Depletion and Amortization Expenses. For the nine months ended September 30, 2012 our DD&A expenses were $61.4 million, or $15.75 per Boe as compared to $58.3 million, or $15.17 per Boe for the nine months ended September 30, 2011.  The increase in DD&A expense is due mainly attributable to the Prize Acquisition during the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.  

General and Administrative and Other Expenses. For the nine months ended September 30, 2012 our general and administrative and other expenses increased to $26.3 million, or $6.76 per Boe, as compared to $22.6 million, or $5.88 per Boe for the nine months ended September 30, 2011.  The increase is mainly attributable to the higher personnel costs associated with increasing our staffing levels to meet our current organizational needs in the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.

Effects of Commodity Derivative Contracts. For the nine months ended September 30, 2012, our realized gains increased to a $35.7 million gain from a realized loss of $79.9 million in the nine months ended September 30, 2011. Unrealized gains on commodity derivative contracts decreased to $12.3 million for the nine months September 30, 2012 from $160.2 million for the nine months ended September 30, 2011.  Unrealized gains and losses result from changes in the future commodity prices as compared to the fixed price of our open commodity derivative contracts.Realized gains and losses result from the settlement of derivative contracts at the market price as compared to the fixed contract price.

The change in realized and unrealized gains (losses) is mainly attributable to increasing oil and gas prices as compared to our fixed price derivative contracts in the three months ended September 30, 2012 as compared to decreasing oil and gas prices in the threemonths ended September 30, 2011, as well as the modification of certain oil derivative contracts during the third quarter of 2011.

Interest Expense, net. Net interest expense decreased to $28.4 million for the nine months ended September 30, 2012 as compared to $39.2 million for the nine months ended September 30, 2012.  The net decrease in realized and unrealized losses on derivative contracts is related to lower interest rates at September 30, 2012 as compared to September 30, 2011 partially offset by a commitment fee of $1.6 million related to the Bridge Loan and an increase in interest expense of $4.6 million related to the Senior Notes in the nine months ended September 30, 2012.

Liquidity and Capital Resources

Our cash flow from operating activities for the nine months ended September 30, 2012 was $110.4 million.

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under our credit facility, and debt and equity offerings. The capital markets continue to experience volatility. Many financial institutions have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to current credit conditions includes our credit facility, debt securities, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

We entered into a Second Amendment to the Credit Agreement on March 16, 2012 to provide for additional derivative contracts to cover production to proved reserves to be acquired.

In April 2012, we entered into the Third Amendment to the Credit Agreement whereby increasing our credit facility from $750 million to $1.5 billion, increasing our borrowing base from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017. 

On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 16 – Subsidiary Guarantors for further details.

29

On July 30, 2012, we, and our wholly-owned subsidiary QRE FC, issued $300 million of 9.25% Senior Notes due 2020. Under the Credit Agreement we are required to reduce our borrowing base by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. As a result of the issuance of the Senior Notes on July 30, 2012, our borrowing base was reduced by $75 million to $655 million from $730 million. On the same date, we made a payment on our outstanding borrowings under our revolving credit facility of $291.5 million using the cash proceeds from the Senior Notes issuance and cash on hand. On October 30, 2012, we were notified of an increase in our borrowing base, as part of our semi-annual borrowing base redetermination, from $655 million to the borrowing base prior to the issuance of the Senior Notes of $730 million. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 9 – Long-Term Debt for further details.

As of September 30, 2012, our liquidity of $355.0 million consisted of $25.1 million of available cash and $329.9 million of availability under our credit facility after giving consideration to $0.1 million of outstanding letters of credit.  As of September 30, 2012, we had $325 million of borrowings outstanding. As of November 8, 2012 we had $325 million of borrowings outstanding with borrowing availability of $404.9 million ($730 million of borrowing base less $325 million of outstanding borrowing and $0.1 million of outstanding letters of credit) under our credit facility. The borrowing base is redetermined as of May 1 and November 1 of each year. The administrative agent of our Credit Agreement accepted the Third Amendment to the Credit Agreement as our May 1 redetermination and our November redetermination was completed on October 30, 2012 as discussed above. In addition, we may request additional capacity for acquisitions of a minimum of the lesser of $50 million or ten percent of the then-existing borrowing base. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility.

A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands. As of September 30, 2012, we had letters of credit in the amount of $0.1 million outstanding for utilities.

On April 17, 2012, we issued 6,202,263 common units representing limited partnership interests in us, and the Fund sold 11,297,737 common units it held in us, to the public pursuant to a registration statement filed with the SEC.  In conjunction with the Equity Offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit.Proceeds from the Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.

On September 28, 2012, we announcedthat our general partner declared a cash distribution to our common and subordinated unitholders and our general partner at the third quarter rate of $0.4875 per unit.  Our Partnership Agreement obligates us to make cash distributions to our preferred unitholders at a rate of $0.21 per unit per quarter. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. We believe our cash flows provided by operating activities will be sufficient to meet our operating requirements for the next twelve months.

As of September 30, 2012, we had a positive working capital balance of $46.7 million.  

30

Capital Expenditures

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage). The primary purpose of maintenance capital is to maintain our production and asset base at a steady level over the long term in order to maintain our distributions per unit. For 2012, we have estimated our maintenance capital expenditures to be approximately $52.0 million. During the nine months ended September 30, 2012, we have expended $80.6 million of total capital expenditures.We currently expect 2012 total capital spending for the development of our oil and natural gas properties to be approximately $85.0 million.

Growth capital expenditures are capital expenditures that are expected to increase our production and the size of our asset base. The primary purpose of growth capital is to acquire producing assets that will primarily increase our distributions per unit and secondarily increase the rate of development and production of our existing properties in a manner which is expected to be accretive to our unitholders.We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisitions of oil and natural gas properties in 2012 through a combination of cash, borrowings under our credit facility and the issuance of equity securities. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. Although we closed the Prize Acquisition in April 2012 and entered into a purchase and sale agreement to purchase additional preliminary properties expected to close in the fourth quarter 2012, as discussed in Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 3,  Acquisitions, we cannot estimate further growth capital expenditures related to acquisitions, including potential acquisitions of producing properties from the Fund, as we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts.

The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for the remainder of 2012. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.

Credit Facilities

Revolving Credit Facility

We entered into a Second Amendment to the Credit Agreement on March 16, 2012 to provide for additional derivative contracts to cover production of proved reserves to be acquired.

In April 2012, we entered into the Third Amendment to the Credit Agreement whereby increasing our credit facility from $750 million to $1.5 billion, increasing our borrowing base from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017. The Third Amendment became effective upon the closing of the Prize Acquisition.

As a result of the issuance of the Senior Notes on July 30, 2012, our borrowing base was reduced by $75 million to $655 million from $730 million. On the same date, we made a payment on our outstanding borrowings under our revolving credit facility of $291.5 million using the cash proceeds from the Senior Notes issuance and cash on hand.  In connection with the reduction of the borrowing base, we wrote-off approximately $0.7 million of deferred loan costs associated with the Credit Agreement. On October 30, 2012, we were informed of an increase in our borrowing base, as part of our semi-annual borrowing base redetermination, from $655 million to the borrowing base prior to the issuance of the Senior Notes of $730 million.

As of September 30, 2012, we had $325 million of borrowings outstanding under our revolving credit facility and $0.1 million of letters of credit outstanding resulting in $329.9 million of borrowing availability. As of

31

December 31, 2011, we had $500.0 million of borrowings and $0.4 million letters of credit outstanding resulting in $129.6 million of borrowing availability

As of November 8, 2012, we had $325 million of borrowings outstanding under our revolving credit facility and $404.9 million of borrowing availability.

As of September 30, 2012, we were party to a five-year credit agreement that governs our $1.5 billion revolving credit facility with a borrowing base of $655 million. The borrowing base is subject to redetermination on a semi-annual basis and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ price assumptions, and other various factors unique to each member bank.The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. In the future, we may be unable to access sufficient capital under our new credit facility as a result of (i) a decrease in our borrowing base due to subsequent borrowing base redeterminations, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge additional oil and natural gas properties as collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the Credit Agreement. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under the Credit Agreement. We completed our semi-annual redetermination on October 30, 2012 as discussed above.

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%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% 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 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee ranging from 0.375% to 0.50% per annum.

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 our 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 unaudited 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 our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our 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 September 30, 2012, we were in compliance with all of the Credit Agreement covenants.

Bridge Loan Commitment

In conjunction with the Prize Acquisition, we entered into a Bridge Loan Commitment to provide an additional $200 million of bank loans to fund the acquisition as needed. We did not utilize any borrowings under the commitment and as of May 10, 2012 the Bridge Loan Commitment was terminated by us. We incurred $1.6 million of commitment fees related to the Bridge Loan Commitment which is recorded in interest expense for the nine months ended September 30, 2012.

32

9.25% Senior Notes

On July 30, 2012, we and our wholly-owned subsidiary QRE FC, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 9.25% Senior Notes, due 2020. The Senior Notes were issued at 98.62% of par. We received approximately $291.2 million of cash proceeds, net of discount and underwriting fees, with total net proceeds of approximately $290.2 million, after $1.0 million ofoffering costs. We used the net proceeds from the sale of the Senior Notes to repay borrowings outstanding under our credit facility. We will have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Our and QRE FC’s obligations under the Senior Notes are guaranteed by OLLC. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor’s, other, debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Note 16 – Subsidiary Guarantors for further details of our guarantors.

The indenture governing the Senior Notes (the “Indenture”) restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, or repurchase, equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.  The Indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the Senior Notes

On September 7, 2012, we filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes to exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012. The exchange offer was completed on November 7, 2012.

Commodity Derivative Contracts

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on the prices of oil and natural gas and our ability to maintain and increase production through acquisitions and exploitation and development projects.  For further discussion of our derivative activities, see Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 5, Derivative Activities.

33

Cash Flows

Cash flows provided (used) by type of activity were as follows for the periods indicated:

		Nine Months Ended
		September 30, 2012		September 30, 2011
Net cash provided by (used in):
Operating activities	$	110,386	$	22,381
Investing activities		(302,602)		(42,590)
Financing activities		199,927		19,226

Operating Activities

Our cash flow from operating activities for the nine months ended September 30, 2012was $110.4 million compared to $22.4 million in cash flow from operating activities for the nine months ended September 30, 2011.  The increase in cash flow from operating activities is mainly attributable tothe realized loss on commodity derivatives modifications during the nine months ended September 30, 2011.

Investing Activities

Our cash flow used in investing activities for the nine months ended September 30, 2012 was $302.6 million compared to cash flows used in investing activities of $42.6 million for the nine months ended September 30, 2011. The increase in cash flow used in investing activities is mainly attributable to the Prize Acquisition and capital spending related to our drilling activities during the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.

Financing Activities

Our cash flow provided by financing activities for the nine months ended September 30, 2012 was $199.9 million compared to cash flows provided by financing activities of $19.2 million for the nine months ended September 30, 2011.  The increase in the cash provided by financing activities is mainly attributed to the increase in net proceeds received from the Equity Offering of $120.1 million and proceeds received from the issuance of the Senior Notes of $295.8 million, partially offset by higher net payments on our revolving credit facility of $216.0 million and an increase in distributions of $39.7 million during the nine months ended September 30, 2012 when compared to the nine months ended September 30, 2011.

Contractual Obligations

There were no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements as of September 30, 2012. Our level of capital expenditures will vary in the future periods depending on the success we experience in our acquisition, development and exploitation activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.

Off-Balance Sheet Arrangements

As of September 30, 2012, we have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited consolidated financial statements, which have been prepared in accordance with U.S. GAAP. Preparation of these unaudited consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our 2011 Annual Report during the three months ended September 30, 2012.

34

Recent Accounting Pronouncements

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

Non-GAAP Financial Measures

We include in this report the non-GAAP financial measures Adjusted EBITDA and Distributable Cash Flow and provide our calculations of Adjusted EBITDA and Distributable Cash Flow and reconciliations to their most directly comparable financial measures calculated and presented in accordance with U.S. GAAP. As discussed below, we have revised our calculation of Adjusted EBITDA from prior periods.

Adjusted EBITDA

We define Adjusted EBITDA as net income:

· Plus:

· Interest expense, including realized and unrealized gains and losses on interest rate derivative contracts;

· Depreciation, depletion, and amortization;

· Accretion of asset retirement obligations;

· Unrealized losses on gas imbalances

· Unrealized losses on commodity derivative contracts;

· Income tax expense;

· Impairments; and

· General and administrative expenses that are allocated to us in accordance with GAAP in excess of the administrative services fee paid by our general partner; 

· Less:

· Income tax benefit;

· Interest income;

· Unrealized gains on gas imbalances; and

· Unrealized gains on commodity derivative contracts.

In our quarterly report for the six months ended June 30, 2012, we revised our calculation of Adjusted EBITDA to, in addition to line items which were added or subtracted from net income in our previous Adjusted EBITDA calculation, add or subtract to net income unrealized losses and gains on gas imbalances, respectively.

We use Adjusted EBITDA, as defined under the Services Agreement, to calculate the quarterly administrative services fee our general partner pays to QRMunder the services agreement between our general partner and QRM. 

35

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

· the cash flow generated by our assets, without regard to financing methods, capital structure or historical cost basis; and

· the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness.

In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

Distributable Cash Flow

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

Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate Distributable Cash Flow in the same manner.

36

The table below presents our calculation of Adjusted EBITDA and Distributable Cash Flow and a reconciliation of Adjusted EBITDA and Distributable Cash Flow to net income, our most directly comparable GAAP financial measures, for each of the periods indicated.

		Three Months Ended				Nine Months Ended
		September 30, 2012		September 30, 2011 1		September 30, 2012		September 30, 2011 1
Reconciliation of net income (loss) to Adjusted EBITDA
and Distributable Cash Flow:
Net income (loss)	$	(45,007)	$	105,165		46,883		87,604
Unrealized losses (gains) on commodity derivative contracts		55,585		(153,378)		(12,328)		(160,233)
Loss on modification of derivative contracts		-		42,654		-		83,399
Unrealized loss (gain) on gas imbalances		371		(703)		73		(143)
Depletion, depreciation and amortization		21,298		19,965		61,428		58,295
Accretion of asset retirement obligations		915		719		2,645		2,033
Interest expense		11,533		19,950		28,398		39,161
Income tax expense (benefit)		(171)		789		528		934
General and administrative expense in excess
of administrative services fee		7,675		8,996		22,374		21,903
Adjusted EBITDA	$	52,199	$	44,157	$	150,001	$	132,953
Cash interest expense		(8,703)		(4,907)		(21,348)		(13,237)
Estimated maintenance capital expenditures		(13,000)		(12,500)		(38,500)		(37,500)
Distributions to preferred unitholders		(3,500)		-		(10,500)		-
Management incentive fee earned by GP		(3,738)		-		(6,121)		-
Distributable Cash Flow	$	23,258	$	26,750	$	73,532	$	82,216

(1) 2011 Adjusted EBITDA has been revised to conform with current period presentation.

The increase in Adjusted EBITDA of $8.0 million to $52.2 million for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011 is mainly attributable to the increase of realized gains on commodity derivative contracts.  The increase of $17.0 million to $150.0 million for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 is mainly attributable to the increase of realized gains on commodity derivative contracts, partially offset by higher production expense, the increase in the quarterly general and administrative fee and a decrease in revenue.

The decrease in Distributable Cash Flow of $3.5 million to $23.3 million in the three months ended September 30, 2012 compared to the three months ended September 30, 2011 is mainly attributable to distributions to preferred untiholders and the management incentive fee earned by QRE GP that were not present in the three months ended September 30, 2011 as well as an increase in cash interest paid, partially offset by an increase in Adjusted EBITDA during the three months ended September 30, 2012 as compared to the three months ended September 30, 2011.  The decrease in Distributable Cash Flow of $8.7 million to $73.5 million for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011 is attributable to distributions to preferred unitholders and the management incentive fee earned by QRE GP that were not present in the nine months ended September 30, 2011 as well as an increase in cash interest paid, partially offset by an increase in Adjusted EBITDA during the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.

37

Item 3.Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the third quarter of 2012 did not change materially from the disclosures in Item 7A of our 2011 Annual Report.

Derivative Instruments and Hedging Activity

We are exposed to various risks including energy commodity price risk. When oil and natural gas prices decline significantly, our ability to finance our capital budget and operations could be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the effect it could have on our operations. The types of derivative instruments that we typically utilize are swaps. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 65% to 85% of our current and anticipated production over the next three-to-five year period. Our hedge policies and objectives may change significantly as commodities prices or price futures change.

We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. We do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. Each of the counterparties to our derivative contracts is a lender in our Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Credit Agreement. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 5, Derivative Activities for additional information on our commodity derivatives.

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates into fixed interest rates.  We are exposed to market risk on our open contracts, to the extent of changes in LIBOR. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 5, Derivative Activities for additional information on our interest rate swaps.

We account for our derivative activities whereby every derivative instrument is recorded on the balance sheet as either an asset or liability measured at fair value. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 5, Derivative Activities for further details.

Item 4.Controls and Procedures

As discussed below, we have determined that newly implemented controls related to our previously identified material weaknesses are designed and operating effectively and, therefore, have concluded that, as of June 30, 2012, such material weaknesses have been remediated.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) we have evaluated, under the supervision and with the participation of our Chief Executive Officer, our principal executive officer and Chief Financial Officer, our principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Actas of September 30, 2012). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Based on the evaluation, the principal executive officer and the principal financial officer concluded that the Partnership's disclosure controls and procedures were effective to provide reasonable assurance as of September 30, 2012.

Material Weakness Previously Identified

As previously discussed in Item 9A. “Controls and Procedures” of our 2011 Annual Report on Form 10-K, we reported material weaknesses in certain control activity levels:

38

· We did not maintain effective controls over the completeness and accuracy of the inputs with respect to the DD&A calculation. Specifically, we did not develop detailed procedures for the accounting staff to follow in order to provide reasonable assurance that the inputs to the calculation are complete and accurate.

· We did not maintain effective controls over the completeness and accuracy of certain calculations used in recording mark to market for derivative expense, the general and administrative allocation and ad valorem taxes. Specifically, we did not maintain effective controls related to the detailed review of these calculations.

Remediation of Previously Identified Material Weaknesses

During the three months ended March 31, 2012, we implemented the following additional procedures to address the material weaknesses in our internal control over financial reporting and the ineffectiveness of our disclosure controls and procedures.

· Re-designed procedures for the DD&A calculation, which includes the review of inputs into the calculation, supporting schedules and analysis.

· Spreadsheets used in the calculations of mark to market for derivative income or expense, the general and administrative allocation and ad valorem taxes have been reviewed to provide reasonable assurance that they are functioning as intended.

· Additional levels of review have been put into place in order to strengthen the overall review process.

· Compensating controls have been strengthened to identify material anomalies.

We have assessed the design and tested the operating effectiveness of the newly implemented controls over the DD&A calculation and the calculations used in recording mark to market for derivative income or expense, the general and administrative allocation and ad valorem taxes and found them to be effective. As such, we concluded the remediation measures described above were sufficient to remediate both material weaknesses in internal control over financial reporting as of June 30, 2012.

Changes in Internal Control over Financial Reporting.

There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please see Part 1, - Item 3 “- Legal Proceedings” in our 2011 Annual Report on Form 10-K. 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. 

Item 1A.Risk Factors

There have been no material changes to the risk factors described in the Partnership’s 2011 Annual Report on Form 10-K and the Partnership’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

None.

39

Item 3.Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Determination of Services Fee Methodology

Beginning on January 1, 2013, QRM will be entitled to a quarterly administrative services fee based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. The fee will include direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If the Fund raises a second fund, the quarterly administrative services costs will be further divided to include the second fund as well. The allocation methodology was developed with the assistance of a third-party consultant with extensive experience in this area. These fees will be included in general and administrative expenses in our consolidated statement of operations. QRM will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.

Item 6.Exhibits

The following documents are included as exhibits to the Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.

Exhibit Number			Description
2.1		---	Purchase and Sale Agreement, dated as of March 19, 2012, by and among QRE Operating, LLC, Prize Petroleum, LLC and Prize Pipeline, LLC (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on March 22, 2012).
3.1		---	Certificate of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.2		---	First Amended and Restated Agreement of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
3.3		---	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, dated as of October 3, 2011 (Incorporated herein by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
3.4		---	Certificate of Formation of QRE GP, LLC (Incorporated by reference to Exhibit 3.4 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.5		---	Amended and Restated Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
4.1		---	Indenture dated as of July 30, 2012 among QR Energy, LP, QRE Finance Corporation and QRE Operating, LLC and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on July 31, 2012).
4.2		---	Registration Rights Agreement dated as of July 30, 2012 among QR Energy, LP, QRE Finance Corporation, QRE Operating, LLC and Citigroup Global Markets Inc., Barclays Capital Inc., Credit Agricole Securities (USA) Inc., RBC Capital Markets, LLC, RBS Securities Inc. and Wells Fargo Securities, LLC, as representatives of the several initial purchasers (Incorporated by reference to Exhibit 4.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on July 31, 2012).
31.1	*	---	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2	*	---	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1	**	---	Certification of the Chief Executive Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	**	---	Certification of the Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	**	---	XBRL Instance Document
101.SCH	**	---	XBRL Taxonomy Extension Schema Document
101.CAL	**	---	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	**	---	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	**	---	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	**	---	XBRL Taxonomy Extension Presentation Linkbase Document

40

* Filed as an exhibit to this Quarterly Report on Form 10-Q.

** Furnished as an exhibit to this Quarterly Report on Form 10-Q.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

QR ENERGY, LP

	By:	QRE GP, LLC,
		its General Partner
Dated:  November 8, 2012	By:	/s/ Alan L. Smith
		Alan L. Smith
		Chief Executive Officer and Director
Dated:  November 8, 2012	By:	/s/ Cedric W. Burgher
		Cedric W. Burgher
		Chief Financial Officer

41

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Alan L. Smith, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of QR Energy, LP(the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

EXHIBIT 31.1

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.    

Date:	November 8, 2012	/s/ Alan L. Smith
		Alan L. Smith
		Chief Executive Officer and Director

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Cedric W. Burgher, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of QR Energy, LP(the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

EXHIBIT 31.2

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 8, 2012	/s/ Cedric W. Burgher
		Cedric W. Burgher
		Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

UNDER SECTION 906 OF THE

SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the Quarterly Report on Form 10-Q of QR Energy, LP (the “Partnership”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Alan L. Smith, Chief Executive Officer of the Partnership, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date:	November 8, 2012	/s/ Alan L. Smith
		Alan L. Smith
		Chief Executive Officer and Director

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

UNDER SECTION 906 OF THE

SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the Quarterly Report on Form 10-Q of QR Energy, LP (the “Partnership”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Cedric W. Burgher, Chief Financial Officer of the Partnership, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date:	November 8, 2012	/s/ Cedric W. Burgher
		Cedric W. Burgher
		Chief Financial Officer

XML

Acquisitions (Summary Of Fair Value Of Assets Acquired And Liabilities Assumed) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 Prize [Member]	Apr. 20, 2012 Prize [Member]
Business Acquisition [Line Items]
Evaluated	$ 1,270,689	$ 975,182		$ 223,740
Unevaluated	9,000			9,000
Asset retirement obligation				(4,738)
Environmental liability			(1,900)	(1,891)
Other current liabilities				(993)
Net assets acquired				$ 225,118

XML

Partners' Capital (Schedule Of Cash Distribution Activity) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended						12 Months Ended
	Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2011
Partners' Cash Distribution Activity [Line Items]
Cash distribution payment date	Nov. 09, 2012		Aug. 10, 2012		May 11, 2012		Feb. 10, 2012
Cash distribution per unit	$ 0.4875
Class C Convertible Preferred [Member]
Partners' Cash Distribution Activity [Line Items]
Cash distribution	$ 3,500		3,500		3,500		3,424
Cash distribution per unit	$ 0.2100	[1],[2]	0.2100	[1],[2]	0.2100	[1],[2]	0.2054	[1],[2]
General Partner [Member]
Partners' Cash Distribution Activity [Line Items]
Cash distribution	20		20		20		16
Limited Partner [Member] | Limited Partners-Public Common [Member]
Partners' Cash Distribution Activity [Line Items]
Cash distribution	18,624		18,584		17,892		8,344
Limited Partner [Member] | Limited Partners-Affiliated - Common [Member]
Partners' Cash Distribution Activity [Line Items]
Cash distribution							5,368
Limited Partner [Member] | Limited Partners-Affiliated - Subordinated [Member]
Partners' Cash Distribution Activity [Line Items]
Cash distribution	3,484		3,484		3,394		3,393
Other Unitholders [Member]
Partners' Cash Distribution Activity [Line Items]
Cash distribution	$ 22,128		22,088		21,306		17,121
Cash distribution per unit	$ 0.4875		0.4875		0.4750		0.4750

[1] (1) Preferred units paid in February 2012 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] Preferred units paid in February 2012 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.

XML

Asset Retirement Obligations (Schedule Of Change In Asset Retirement Obligation) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Asset Retirement Obligations [Abstract]
Asset retirement obligations, Beginning balance			$ 65,701
Asset retirement obligations, Assumed in acquisition			4,738
Asset retirement obligations, Divested			(23)
Asset retirement obligations, Revisions to previous estimates			2,928
Asset retirement obligations, Liabilities incurred			1,208
Asset retirement obligations, Liabilities settled			(2,845)
Asset retirement obligations, Accretion expense	915	719	2,645	2,033
Asset retirement obligations, Ending balance	74,352		74,352
Less: Current portion of asset retirement obligations	(845)		(845)		(348)
Asset retirement obligations - non-current	$ 73,507		$ 73,507		$ 65,353

XML

Commitments And Contingencies (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012 Prize [Member]	Apr. 20, 2012 Prize [Member]
Business Acquisition, Contingent Consideration [Line Items]
Quarterly administration fee equal to percentage of adjusted EBITDA due to QRM	3.50%
Estimated environmental liability		$ 1,900	$ 1,891

XML

Derivative Activities (Gains (Losses) Of Derivative Contacts By Statement Of Operations Location) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instrument	$ (45,382)		$ 98,741		$ 37,904		$ 53,435
Unrealized gain (loss) on derivative instrument					23,011		135,590
Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instrument	(42,210)	[1]	114,306	[1]	47,996	[1]	80,309	[1]
Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instrument	(3,172)	[2]	(15,565)	[2]	(10,092)	[2]	(26,874)	[2]
Realized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instrument	(2,770)		(40,041)		14,893		(82,155)
Realized Gain (Loss) [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instrument	13,375	[1]	(39,072)	[1]	35,668	[1]	(79,924)	[1]
Realized Gain (Loss) [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instrument	(16,145)	[2]	(969)	[2]	(20,775)	[2]	(2,231)	[2]
Unrealized Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivative instrument	(42,612)		138,782		23,011		135,590
Unrealized Gain (Loss) [Member] | Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instrument	(55,585)		153,378		12,328		160,233
Unrealized gain (loss) on derivative instrument	(55,585)	[1]	153,378	[1]	12,328	[1]	160,233	[1]
Unrealized Gain (Loss) [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on derivative instrument	$ 12,973	[2]	$ (14,596)	[2]	$ 10,683	[2]	$ (24,643)	[2]

[1] Gain (loss) on commodity derivative contracts is located in other income (expense) in the consolidated statements of operations.

[2] Gain (loss) on interest rate derivatives contracts is recorded as part of interest expense and is located in other income (expense) in the consolidated statements of operations.

XML

Unit-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2012

Unit-Based Compensation [Abstract]

Summary Of Unit-Based Awards

		Weighted			Weighted
		Average			Average
	Number of	Grant-Date		Number of	Grant-Date
	Service Restricted units	Fair Value		Performance units	Fair Value
Unvested units, December 31, 2011	271	$	20.33	-	$	-
Granted	428		18.18	121		18.06
Forfeited	(35)		20.23	-		-
Vested	(18)		20.16	-		-
Unvested units, September 30, 2012	646	$	18.80	121	$	18.06

XML

Net Income/(Loss) Per Limited Partner Unit (Calculation Of Net Loss Per Limited Partner Unit) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Schedule Of Earnings Per Partner Unit [Line Items]
Net income (loss)	$ (45,007)		$ 105,165		$ 46,883		$ 87,604
Net income	(45,007)		105,165		46,883		87,604
Net income (loss) attributable to predecessor operations			(53,235)				(49,091)
Distribution on Class C convertible preferred units	(3,500)				(10,500)
Amortization of preferred unit discount	(3,751)				(11,140)
Net income (loss) available to other unitholders	(52,258)		51,930		25,243		38,513
Less: general partner's interest in net income (loss)	3,705		52		6,150		39
Limited partners' interest in net income (loss)	(55,963)		51,878		19,093		38,474
Common unitholders' interest in net income (loss)	(46,930)		41,540		16,717		30,829
Subordinated unitholders' interest in net income (loss)	$ (9,033)		$ 10,338		$ 2,376		$ 7,644
Subordinated units (basic and diluted) (in units)	7,146,000	[1]	7,146,000	[1]	7,146,000	[1]	7,146,000	[1]
Weighted average preferred units outstanding					16,666,667
Limited Partners-Affiliated - Common [Member]
Schedule Of Earnings Per Partner Unit [Line Items]
Unitholders' (basic) (in dollars per unit)	$ (1.25)		$ 1.45		$ 0.49		$ 1.07
Unitholders' (diluted) (in dollars per unit)	$ (1.25)		$ 1.45		$ 0.49		$ 1.07
Common units (basic) (in units)	37,425,000	[1]	28,713,000	[1]	34,347,000	[1]	28,698,000	[1]
Common units (diluted) (in units)	37,425,000	[1]	28,713,000	[1]	34,347,000	[1]	28,698,000	[1]
Limited Partners-Affiliated - Subordinated [Member]
Schedule Of Earnings Per Partner Unit [Line Items]
Unitholders' (basic) (in dollars per unit)	$ (1.26)		$ 1.45		$ 0.33		$ 1.07
Unitholders' (diluted) (in dollars per unit)	$ (1.26)		$ 1.45		$ 0.33		$ 1.07

[1] For the three and nine months ended September 30, 2012, we had weighted average preferred units outstanding of 16,666,667, which are contingently convertible. These units could potentially dilute earnings per unit in the future and have not been included in the earnings per unit calculation for the three and nine months ended September 30, 2012, as they were anti-dilutive for the periods.

XML

Acquisitions (Tables)

9 Months Ended

Sep. 30, 2012

Acquisitions [Abstract]

Summary Of Fair Value Of Assets Acquired And Liabilities Assumed

Oil and gas properties
Evaluated	$	223,740
Unevaluated		9,000
Asset retirement obligation		(4,738)
Environmental liability		(1,891)
Other current liabilities		(993)
Net assets acquired	$	225,118

Proforma Financial Results

		Three Months Ended				Nine Months Ended
		(Unaudited)				(Unaudited)
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
		Actual		Pro Forma		Pro Forma		Pro Forma
Total Revenue	$	64,969	$	72,815	$	205,081	$	221,574
Operating income	$	8,565	$	14,292	$	33,314	$	58,349
Net income (loss)	$	(45,007)	$	107,530	$	51,983	$	97,577
Net income (loss) per unit:
Common unitholders' (basic)	$	(1.25)	$	1.21	$	0.54	$	1.08
Common unitholders' (diluted)	$	(1.25)	$	1.21	$	0.54	$	1.08
Subordinated units (basic)	$	(1.26)	$	1.21	$	0.53	$	1.08
Subordinated units (diluted)	$	(1.26)	$	1.21	$	0.53	$	1.08

XML

Long-Term Debt (Narrative) (Details) (USD $)	1 Months Ended	3 Months Ended	9 Months Ended
	Jul. 31, 2012	Sep. 30, 2012	Sep. 30, 2012	Nov. 08, 2012	Oct. 30, 2012	Jul. 30, 2012	Apr. 11, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Number of days after fiscal year end to provide audited financial statements for credit agreement			90 days
Number of days after fiscal quarter end to provide unaudited financial statements for credit agreement			45 days
Senior notes issuance date			Jul. 30, 2012
Senior notes face amount						$ 300,000,000
Senior notes stated interest rate						9.25%
Senior notes, par percentage						98.62%
Proceeds from issuance of senior notes	291,200,000
Proceeds from the issuance of senior notes, net of offering costs	290,200,000
Offering costs of senior notes	1,000,000
Redeemable percentage of aggregate principal amount of debt with proceeds from public or private offering prior to August 15, 2015			35.00%
Possible repurchase percentage of principal amount of senior notes			101.00%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit Agreement, initiation date			Dec. 22, 2010
Credit Agreement, amount outstanding		325,000,000	325,000,000	325,000,000				500,000,000
Credit Agreement, remaining borrowing capacity		329,900,000	329,900,000	404,900,000				129,600,000
Credit Agreement, maximum borrowing capacity		1,500,000,000	1,500,000,000				750,000,000
Credit Agreement, current borrowing capacity		730,000,000	730,000,000		730,000,000	655,000,000	630,000,000
Credit Agreement, expiration date			Apr. 20, 2017
Percentage multiplied by stated principal amount of debt issuance to reduce borrowing base	0.25%
Credit Agreement, interest rate description			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%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% 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 1.50% to 2.50% per annum according to the borrowing base usage.
Total debt to EBITDAX ratio to be maintained for Credit Agreement			4.0
Current ratio to be maintained for Credit Agreement			1.0
Credit Agreement, reduction in borrowing capacity	75,000,000
Credit Agreement, repayment	291,500,000
Credit Agreement, write-off of deferred loan costs		700,000
Revolving Credit Facility [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Credit Agreement, amount outstanding		100,000	100,000					400,000
Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Percentage of oil and gas properties collateralized by liens			80.00%
Credit Agreement, unused portion, commitment fee percentage			0.375%
Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Credit Agreement, unused portion, commitment fee percentage			0.50%
Interest Rate Option 1 [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Interest percentage added to Federal Funds Rate			0.50%
Interest percentage added to LIBOR Rate			1.00%
Interest Rate Option 1 [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Credit Agreement, basis spread on variable rate		0.50%	0.50%
Interest Rate Option 1 [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Credit Agreement, basis spread on variable rate		1.50%	1.50%
Interest Rate Option 2 [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Credit Agreement, basis spread on variable rate		1.50%	1.50%
Interest Rate Option 2 [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Credit Agreement, basis spread on variable rate		2.50%	2.50%
Forecasted Production In Current Year Attributable To Proved Developed Producing Reserves And Reserves To Be Acquired [Member]
Debt Instrument [Line Items]
Percentage of forecasted production prohibiting entering into derivative contracts			90.00%
Forecasted Production For The Next Two Years From Total Proved Reserves And Total Proved Reserves To Be Acquired [Member]
Debt Instrument [Line Items]
Percentage of forecasted production prohibiting entering into derivative contracts			85.00%
Forecasted Production For Three Plus Years From Total Proved Reserves And Total Proved Reserves To Be Acquired [Member]
Debt Instrument [Line Items]
Percentage of forecasted production prohibiting entering into derivative contracts			75.00%
Bridge Loan [Member]
Debt Instrument [Line Items]
Bridge loan, maximum borrowing capacity			200,000,000
Bridge loan, termination date			May 10, 2012
Bridge loan, commitment fees			$ 1,600,000

XML

Fair Value Measurements (Schedule Of Fair Value Of Financial Assets And Liablilities By Level) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset derivative instruments	$ 123,932	$ 103,253
Liability derivative instruments	19,332	26,475
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from commodity derivative instruments	123,932	103,233
Assets from interest rate derivative instruments		20
Liabilities from commodity derivative instruments	6,062	2,502
Liabilities from interest rate derivative instruments	13,270	23,973
Asset derivative instruments	123,932	103,253
Liability derivative instruments	19,332	26,475
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets from commodity derivative instruments	123,932	103,233
Assets from interest rate derivative instruments		20
Liabilities from commodity derivative instruments	6,062	2,502
Liabilities from interest rate derivative instruments	13,270	23,973
Asset derivative instruments	123,932	103,253
Liability derivative instruments	$ 19,332	$ 26,475

XML

Organization And Operations (Details) (USD $)	0 Months Ended		9 Months Ended							0 Months Ended		9 Months Ended					0 Months Ended			1 Months Ended	9 Months Ended	0 Months Ended			9 Months Ended
	Apr. 17, 2012	Jan. 03, 2011	Sep. 30, 2012	Jul. 30, 2012	Dec. 31, 2011	Oct. 03, 2011	Oct. 01, 2011	Dec. 22, 2010 QRE GP [Member]	Oct. 03, 2011 Class C Convertible Preferred [Member]	Apr. 17, 2012 Limited Partners-Public Common [Member]	Dec. 22, 2010 Limited Partners-Public Common [Member]	Sep. 30, 2012 Limited Partners-Public Common [Member]	Sep. 30, 2012 General Partner [Member] QRE GP [Member]	Sep. 30, 2012 Limited Partner [Member] Limited Partners-Public Common [Member]	Sep. 30, 2012 Prize [Member]	Apr. 20, 2012 Prize [Member]	Apr. 17, 2012 Over-Allotment [Member]	Apr. 17, 2012 Fund [Member]	Oct. 01, 2011 Fund [Member]	Oct. 31, 2010 Fund [Member]	Sep. 30, 2012 Fund [Member]	Apr. 17, 2012 Fund [Member] Limited Partners-Public Common [Member]	Dec. 22, 2010 Fund [Member] Limited Partners-Affiliated - Common [Member]	Dec. 22, 2010 Fund [Member] Limited Partners-Affiliated - Subordinated [Member]	Sep. 30, 2012 Fund [Member] Limited Partner [Member]	Sep. 30, 2012 Fund [Member] Limited Partner [Member] Limited Partners-Public Common [Member]	Sep. 30, 2012 Fund [Member] Limited Partner [Member] Limited Partners-Affiliated - Common [Member]
Organization And Operations [Line Items]
Partners' capital account, units, sold in public offering		2,250,000								6,202,263	15,000,000			8,827,263			2,625,000					11,297,737				11,297,737	(11,297,737)
Partners' capital account, price per unit, sold in public offering	$ 19.18																	19.18
Partners' capital account, units, exchange for net assets																							11,297,737	7,145,866
Partners' capital account, units, capital contribution								35,729
Partners' capital account, public sale of units net of offering costs	$ 162,000,000	$ 42,000,000
Class C convertible preferred unitholders issued (in units)			16,666,667		16,666,667				16,666,667
Period of time for the underwriters over-allotment option																	30 days
Value of preferred units issued			369,278,000		358,138,000
Debt assumption for oil and gas properties						227,000,000
Preferred units, fair value of preferred unit							$ 21.27
Preferred unit valuation							354,500,000
Net assets contributed by Fund																			252,000,000
Deemed Fund distribution																				102,500,000
Date of acquisition															Apr. 20, 2012
Effective date of acquisition															Jan. 01, 2012
Cash paid for acquisition																225,000,000
Transaction costs	500,000
Underwriter's discount	6,800,000
Senior notes issuance date			Jul. 30, 2012
Senior notes face amount				$ 300,000,000
Senior notes stated interest rate				9.25%
Ownership percentage												61.10%	0.10%								38.80%				38.80%

XML

Partners' Capital (Narrative) (Details) (USD $)	0 Months Ended			6 Months Ended	9 Months Ended				0 Months Ended	9 Months Ended	0 Months Ended		9 Months Ended	0 Months Ended		9 Months Ended
	Apr. 25, 2012	Apr. 17, 2012	Jan. 03, 2011	Oct. 15, 2012	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Sep. 30, 2012 QRE GP [Member]	Apr. 17, 2012 Fund [Member]	Sep. 30, 2012 Fund [Member]	Apr. 17, 2012 Limited Partners-Public Common [Member]	Dec. 22, 2010 Limited Partners-Public Common [Member]	Sep. 30, 2012 Limited Partners-Public Common [Member]	Apr. 17, 2012 Limited Partners-Public Common [Member] Fund [Member]	Apr. 17, 2012 Over-Allotment [Member]	Sep. 30, 2012 General Partner [Member]	Sep. 30, 2012 General Partner [Member] QRE GP [Member]
Partners' Capital Activity [Line Items]
Partners' capital account, units, sold in public offering			2,250,000								6,202,263	15,000,000		11,297,737	2,625,000
Partners' capital account, price per unit, sold in public offering		$ 19.18							19.18
Costs associated with the Offering		$ 500,000
Underwriter's discount		6,800,000
Number of days for underwriters' allotment option					30 days
Proceeds from unit offering, net of offering costs				162,000,000	161,958,000	41,963,000
Ownership percentage										38.80%			61.10%				0.10%
General Partners' account, units sold to QRE GP	6,018															6,018
General Partners' account, price per unit, sold to QRE GP	$ 19.18
General partner, outstanding (in units)					41,747		35,729	41,747
Cash distribution per unit					$ 0.4875
Distributions payable					$ 25,628,000		$ 20,545,000

XML

Related Party Transactions (Changes In The Affiliate Payable/Receivables Balance) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Related Party Transactions [Abstract]
Net affiliate receivable as of December 31, 2011	$ 3,734
Revenues and other increases	187,036
Expenditures	(155,351)
Settlements from the Fund	(26,100)
Net affiliate payable as of September 30, 2012	$ 9,319

XML

Income Taxes (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Income Taxes [Abstract]
Deferred tax asset, gross	$ 300,000		$ 300,000		$ 300,000
Deferred taxes liability, gross	400,000		400,000		100,000
Deferred tax asset, net					270,000
Deferred tax liability, net	102,000		102,000
Deferred taxes	102,000		102,000
Income tax expense (benefit)	$ (171,000)	$ 789,000	$ 528,000	$ 934,000

XML

Acquisitions

9 Months Ended

Sep. 30, 2012

Acquisitions [Abstract]

Acquisitions

NOTE 3 – ACQUISITIONS

Prize Properties

On April 20, 2012 we closed the Prize Acquisition. We acquired predominantly low decline, long life oil properties, almost all of which are located in the Ark-La-Tex area, for $225million in cash after customary purchase price adjustments. The acquired properties had estimated proved reserves as of December 31, 2011 utilizing SEC case pricingof13.3 MMBoe. The acquisition had an effective date of January 1, 2012.

The Prize Acquisition qualified as a business combination and was accounted for under the purchase method of accounting.  Effective April 20, 2012 the results of operations of the acquired Prize assets are included in our unaudited statement of operations for the three and nine months ended September 30, 2012. Accordingly, we recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. The fair value measurements of the oil and gas properties and asset retirement obligations were measured using valuation techniques and inputs that convert future cash flows to a single discounted amount.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisition closing date (in thousands):

Oil and gas properties
Evaluated	$	223,740
Unevaluated		9,000
Asset retirement obligation		(4,738)
Environmental liability		(1,891)
Other current liabilities		(993)
Net assets acquired	$	225,118

The above estimated fair values of assets acquired and liabilities assumed are provisional and are based on the information that was available as of the acquisition date to estimate the fair value of assets acquired and liabilities assumed. We believe that the information provides a reasonable basis for estimating the fair values of assets acquired and liabilities assumed. We expect to finalize the valuation and complete the purchase price allocation as soon as practicable but no later than oneyear from the acquisition date.

The costs associated with the Prize Acquisitionof  $1.0 million are recorded in the acquisition and transaction costs caption of the consolidated statement of operations for ninemonths ended September 30, 2012.In conjunction with the Prize Acquisition, we assumed an estimated environmental liability of $1.9 million. Refer to Note 11 – Commitments And Contingencies for further details.

Since the closing date, revenues of $8.7 million and $15.2 million and operating expenses of $3.4 million and $6.1 million related to the operation of the Prize properties are included in the consolidated statements of operations for the three and nine months ended September 30, 2012. The following unaudited consolidated income statement information provideunaudited actual results for the three months ended September 30, 2012 and pro forma income statement information for the nine months endedSeptember 30, 2012 and for the three and nine months ended September 30, 2011, which assumes the Prize Acquisition had occurred on January 1, 2011. The unaudited pro forma results reflect certain adjustments related to the acquisition, such as increased depreciation and amortization expense on the assets acquired from Prize resulting from the fair value of assets acquired. The unaudited pro forma financial results may not be indicative of the results that would have occurred hadthe acquisition been completed at the beginning of the periods presented, nor are they indicative of future results of operations.

		Three Months Ended				Nine Months Ended
		(Unaudited)				(Unaudited)
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
		Actual		Pro Forma		Pro Forma		Pro Forma
Total Revenue	$	64,969	$	72,815	$	205,081	$	221,574
Operating income	$	8,565	$	14,292	$	33,314	$	58,349
Net income (loss)	$	(45,007)	$	107,530	$	51,983	$	97,577
Net income (loss) per unit:
Common unitholders' (basic)	$	(1.25)	$	1.21	$	0.54	$	1.08
Common unitholders' (diluted)	$	(1.25)	$	1.21	$	0.54	$	1.08
Subordinated units (basic)	$	(1.26)	$	1.21	$	0.53	$	1.08
Subordinated units (diluted)	$	(1.26)	$	1.21	$	0.53	$	1.08

On October 26, 2012, we entered into a purchase and sale agreement with a private seller to purchase predominantly oil and natural gas properties in the Ark-La-Tex area for approximately $215 million. Refer to Note 17 – Subsequent Events for further details.

XML

Supplemental Cash Flow Information (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest	$ 33,322		$ 13,236
Change in accrued capital expenditures	(6,660)		2,165
Interest rate swaps novated from the Fund			2,875
General and administrative expense allocated from the Fund	22,224		21,252
Amortization of increasing rate distributions	$ 11,140	[1]

[1] Amortization of increasing rate distributions is offset in the preferred unitholder’s capital account by a non-cash distribution.

XML

Derivative Activities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	9 Months Ended
	Jul. 31, 2012	Sep. 30, 2012
Derivative Activities [Abstract]
Realized loss on early termination of a portion of interest rate derivative contract	$ 15
Deferred premiums associated with natural gas derivative instruments		$ 4.9

XML

Accrued And Other Liabilities (Tables)

9 Months Ended

Sep. 30, 2012

Accrued And Other Liabilities [Abstract]

Schedule Of Accrued And Other Liabilities

		September 30, 2012		December 31, 2011
Distributions payable	$	25,628	$	20,545
Accrued capital spending		2,931		9,591
Production expense accrual		16,925		12,872
Senior notes interest accrual		4,625		-
Management incentive fee		4,538		1,572
Other		5,535		5,447
	$	60,182	$	50,027

XML

Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2012

Asset Retirement Obligations [Abstract]

Schedule Of Change In Asset Retirement Obligation

		Nine Months Ended
		September 30, 2012
Beginning of period	$	65,701
Assumed in acquisition		4,738
Divested		(23)
Revisions to previous estimates		2,928
Liabilities incurred		1,208
Liabilities settled		(2,845)
Accretion expense		2,645
End of period	$	74,352
Less: Current portion of asset retirement obligations		(845)
Asset retirement obligations - non-current	$	73,507

XML

Net Income/(Loss) Per Limited Partner Unit (Narrative) (Details)	9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Limited Partners-Public Common [Member]
Schedule Of Earnings Per Partner Unit [Line Items]
Ownership percentage	61.10%
Limited partners unitholders, outstanding (in units)	37,434,720	17,292,279
Limited Partners-Affiliated - Subordinated [Member]
Schedule Of Earnings Per Partner Unit [Line Items]
Limited partners unitholders, outstanding (in units)	7,145,866	7,145,866
General Partner [Member] | QRE GP [Member]
Schedule Of Earnings Per Partner Unit [Line Items]
Ownership percentage	0.10%

XML

Derivative Activities (Notional Volumes Of Commodity Derivative Contracts) (Details)	Oct. 31, 2012	Sep. 30, 2012
Oil Positions [Member] | Jul 1 - Dec 31, 2012 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day		5,872
Average price		100.34
Oil Positions [Member] | 2013 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	627	6,543
Average price	88.20	99.75
Oil Positions [Member] | 2014 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	1,000	5,661
Average price	87.53	97.91
Oil Positions [Member] | 2014 [Member] | WTI [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		425
Average floor price		90.00
Average ceiling price		106.50
Oil Positions [Member] | 2015 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	931	4,540
Average price	85.65	96.87
Oil Positions [Member] | 2015 [Member] | WTI [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		1,025
Average floor price		90.00
Average ceiling price		110.00
Oil Positions [Member] | 2016 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	868	2,480
Average price	84.65	92.07
Oil Positions [Member] | 2016 [Member] | WTI [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		1,500
Average floor price		80.00
Average ceiling price		102.00
Oil Positions [Member] | 2017 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	817	3,730
Average price	84.35	87.57
Natural Gas Positions [Member] | Jul 1 - Dec 31, 2012 [Member] | NYMEX [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day		30,213
Average price		5.89
Natural Gas Positions [Member] | Jul 1 - Dec 31, 2012 [Member] | NYMEX [Member] | Basis Swaps [Member]
Derivative [Line Items]
Hedged volume per day		20,709
Average price		(0.15)
Natural Gas Positions [Member] | Jul 1 - Dec 31, 2012 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		2,609
Average floor price		6.50
Average ceiling price		8.60
Natural Gas Positions [Member] | 2013 [Member] | NYMEX [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day		29,674
Average price		6.07
Natural Gas Positions [Member] | 2013 [Member] | NYMEX [Member] | Basis Swaps [Member]
Derivative [Line Items]
Hedged volume per day		18,466
Average price		(0.17)
Natural Gas Positions [Member] | 2013 [Member] | Henry Hub [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	767
Average price	3.99
Natural Gas Positions [Member] | 2013 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		2,466
Average floor price		6.50
Average ceiling price		8.65
Natural Gas Positions [Member] | 2014 [Member] | NYMEX [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day		25,907
Average price		6.23
Natural Gas Positions [Member] | 2014 [Member] | NYMEX [Member] | Basis Swaps [Member]
Derivative [Line Items]
Hedged volume per day		17,066
Average price		(0.19)
Natural Gas Positions [Member] | 2014 [Member] | Henry Hub [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	715
Average price	4.27
Natural Gas Positions [Member] | 2014 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		4,966
Average floor price		5.74
Average ceiling price		7.51
Natural Gas Positions [Member] | 2015 [Member] | NYMEX [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day		6,520
Average price		5.43
Natural Gas Positions [Member] | 2015 [Member] | NYMEX [Member] | Basis Swaps [Member]
Derivative [Line Items]
Hedged volume per day		14,400
Average price		(0.19)
Natural Gas Positions [Member] | 2015 [Member] | Henry Hub [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	671
Average price	4.43
Natural Gas Positions [Member] | 2015 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		18,000
Average floor price		5.00
Average ceiling price		7.48
Natural Gas Positions [Member] | 2015 [Member] | Henry Hub [Member] | Put [Member]
Derivative [Line Items]
Hedged volume per day		420
Average price		4.0
Natural Gas Positions [Member] | 2016 [Member] | NYMEX [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day		11,350
Average price		4.27
Natural Gas Positions [Member] | 2016 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day	630
Average floor price	4.00
Average ceiling price	5.55
Natural Gas Positions [Member] | 2016 [Member] | Henry Hub [Member] | Put [Member]
Derivative [Line Items]
Hedged volume per day		11,350
Average price		4.0
Natural Gas Positions [Member] | 2017 [Member] | NYMEX [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day		10,445
Average price		4.47
Natural Gas Positions [Member] | 2017 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day	595
Average floor price	4.00
Average ceiling price	6.15
Natural Gas Positions [Member] | 2017 [Member] | Henry Hub [Member] | Put [Member]
Derivative [Line Items]
Hedged volume per day		10,445
Average price		4.0

XML

Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2012

Long-Term Debt [Abstract]

Schedule Of Long-Term Debt

		September 30, 2012		December 31, 2011
Senior revolving credit facility	$	325,000	$	500,000
9.25% Senior Notes due 2020(1)		295,946		-
Total long-term debt	$	620,946	$	500,000

⁽¹⁾ The amount is net of unamortized discount of $4.1 million as of September 30, 2012.

XML

Partners' Capital (Tables)

9 Months Ended

Sep. 30, 2012

Partners' Capital [Abstract]

Schedule Of Partners' Units Activity

	Preferred Units	General Partner	Public Common	Affiliated Common	Subordinated
Balance - December 31, 2011	16,666,667	35,729	17,292,279	11,297,737	7,145,866
Vested units awarded under our Long Term Incentive
Performance Plan	-	-	18,359	-	-
Reduction in units to cover individuals' tax withholdings	-	-	(918)	-	-
Issuance of units to General Partner	-	6,018	-	-	-
Affiliated unit sale to the public	-	-	11,297,737	(11,297,737)	-
Unit offering	-	-	8,827,263	-	-
Balance - September 30, 2012	16,666,667	41,747	37,434,720	-	7,145,866

Schedule Of Cash Distribution Activity

						Limited Partners
							Affiliated
Payment Date	For the period ended	Distributions to Preferred Unitholders		Distributions per Preferred Unit(1)	General Partner	Public Common	Common	Subordinated	Total Distributions to Other Unitholders	Distributions per other units
(In thousands, except per unit amounts)
February 10, 2012	December 31, 2011	3,424	$	0.2054	16	8,344	5,368	3,393	17,121	0.4750
May 11, 2012	March 31, 2012	3,500	$	0.21	20	17,892	-	3,394	21,306	0.4750
August 10, 2012	June 30, 2012	3,500	$	0.21	20	18,584	-	3,484	22,088	0.4875
November 9, 2012	September 30, 2012	3,500	$	0.21	20	18,624	-	3,484	22,128	0.4875

(1) Preferred units paid in February 2012 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.

XML

Significant Accounting Policies

9 Months Ended

Sep. 30, 2012

Significant Accounting Policies [Abstract]

Significant Accounting Policies

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles in the United States (“U.S. GAAP”) for complete annual financial statements. During interim periods, the Partnership follows the accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”), filed with the SEC. The unaudited consolidated financial statements for the three and ninemonths ended September 30, 2012 and 2011 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. Prior period amounts have been revised to conform to current period presentation. Operating results for the three and nine months ended September 30, 2012 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2012. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our 2011 Annual Report.

The Partnership’s historical financial statements previously filed with the SEC have been revised in this quarterly report on Form 10-Q 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 January 1, 2011 to September 30, 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 set forth in Note 2 of the Notes to Consolidated Financial Statements in our 2011 Annual Report.

Accounting Policy Updates/Revisions

The accounting policies followed by the Partnership are set forth in Note 2 – Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in our 2011 Annual Report. There have been no significant changes to these policies during the ninemonths ended September 30, 2012 with the exception of the updates below.

Unevaluated Properties

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

Business Combinations

We account for all business combinations using the purchase method, in accordance with U.S. GAAP. Under the purchase method of accounting, a business combination is accounted for at the 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. The difference between the fair value of assets acquired and liabilities assumed over the cost of the entity, if any, is recorded as either goodwill or a bargain purchase gain. The Partnership has not recognized any goodwill from business combinations.

Recent Accounting Pronouncements

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). The amendments in ASU 2011-04 are the result of the FASB's and the International Accounting Standards Board's (“IASB”) work to develop common requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP 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 amendment was adopted by us on January 1, 2012 and did not 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 instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a 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.

XML

Net Income/(Loss) Per Limited Partner Unit (Tables)

9 Months Ended

Sep. 30, 2012

Net Income/(Loss) Per Limited Partner Unit [Abstract]

Calculation Of Net Loss Per Limited Partner Unit

		Three Months Ended				Nine Months Ended
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
Net income (loss)	$	(45,007)	$	105,165	$	46,883	$	87,604
Net income (loss) attributable to predecessor operations		-		(53,235)		-		(49,091)
Distribution on Class C convertible preferred units		(3,500)		-		(10,500)		-
Amortization of preferred unit discount		(3,751)		-		(11,140)		-
Net income (loss) available to other unitholders		(52,258)		51,930		25,243		38,513
Less: general partner's interest in net income (loss)		3,705		52		6,150		39
Limited partners' interest in net income (loss)	$	(55,963)	$	51,878	$	19,093	$	38,474
Common unitholders' interest in net income (loss)	$	(46,930)	$	41,540	$	16,717	$	30,829
Subordinated unitholders' interest in net income (loss)	$	(9,033)	$	10,338	$	2,376	$	7,644
Net loss per limited partner unit:
Common unitholders' (basic)	$	(1.25)	$	1.45	$	0.49	$	1.07
Common unitholders' (diluted)		(1.25)		1.45		0.49		1.07
Subordinated unitholders' (basic)	$	(1.26)	$	1.45	$	0.33	$	1.07
Subordinated unitholders' (diluted)		(1.26)		1.45		0.33		1.07
Weighted average number of limited partner units outstanding (1):
Common units (basic)		37,425		28,713		34,347		28,698
Common units (diluted)		37,425		28,713		34,347		28,698
Subordinated units (basic and diluted)		7,146		7,146		7,146		7,146

⁽¹⁾ For the three and nine months ended September 30, 2012, we had weighted average preferred units outstanding of 16,666,667, which are contingently convertible.  These units could potentially dilute earnings per unit in the future and have not been included in the earnings per unit calculation for the three and nine months ended September 30, 2012, as they were anti-dilutive for the periods.

XML

Acquisitions (Proforma Financial Results) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Prize [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Total Revenue, Proforma	$ 64,969	$ 72,815	$ 205,081	$ 221,574
Operating income, Proforma	8,565	14,292	33,314	58,349
Net income (loss), Proforma	$ (45,007)	$ 107,530	$ 51,983	$ 97,577
Limited Partners-Affiliated - Common [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Unitholders' (basic) (in dollars per unit)	$ (1.25)	$ 1.45	$ 0.49	$ 1.07
Limited Partners-Affiliated - Common [Member] | Prize [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Unitholders' (basic) (in dollars per unit), Proforma	$ (1.25)	$ 1.21	$ 0.54	$ 1.08
Unitholders' (diluted) (in dollars per unit), Proforma	$ (1.25)	$ 1.21	$ 0.54	$ 1.08
Limited Partners-Affiliated - Subordinated [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Unitholders' (basic) (in dollars per unit)	$ (1.26)	$ 1.45	$ 0.33	$ 1.07
Limited Partners-Affiliated - Subordinated [Member] | Prize [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Unitholders' (basic) (in dollars per unit), Proforma	$ (1.26)	$ 1.21	$ 0.53	$ 1.08
Unitholders' (diluted) (in dollars per unit), Proforma	$ (1.26)	$ 1.21	$ 0.53	$ 1.08

XML

Partners' Capital (Schedule Of Partners' Unit Activity) (Details)	0 Months Ended						9 Months Ended					0 Months Ended	9 Months Ended
	Apr. 25, 2012	Jan. 03, 2011	Apr. 17, 2012 Limited Partners-Public Common [Member]	Dec. 22, 2010 Limited Partners-Public Common [Member]	Sep. 30, 2012 Class C Convertible Preferred [Member]	Dec. 31, 2011 Class C Convertible Preferred [Member]	Sep. 30, 2012 General Partner [Member]	Sep. 30, 2012 Limited Partner [Member] Limited Partners-Public Common [Member]	Dec. 31, 2011 Limited Partner [Member] Limited Partners-Affiliated - Common [Member]	Sep. 30, 2012 Limited Partner [Member] Limited Partners-Affiliated - Subordinated [Member]	Dec. 31, 2011 Limited Partner [Member] Limited Partners-Affiliated - Subordinated [Member]	Apr. 17, 2012 Fund [Member] Limited Partners-Public Common [Member]	Sep. 30, 2012 Fund [Member] Limited Partner [Member] Limited Partners-Public Common [Member]	Sep. 30, 2012 Fund [Member] Limited Partner [Member] Limited Partners-Affiliated - Common [Member]
Partners' Unit Capital Activity [Line Items]
Balance - December 31, 2012					16,666,667	16,666,667	35,729	17,292,279	11,297,737	7,145,866	7,145,866
Vested units awarded under our Long Term Incentive Performance Plan								18,359
Reduction in units to cover individuals' tax withholdings								(918)
Issuance of units to General Partner	6,018						6,018
General Partners' account, units sold to QRE GP	6,018						6,018
Units sold to public		2,250,000	6,202,263	15,000,000				8,827,263				11,297,737	11,297,737	(11,297,737)
Balance - June 30, 2012					16,666,667	16,666,667	41,747	37,434,720	11,297,737	7,145,866	7,145,866

XML

Consolidated Balance Sheets (Unaudited) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Current assets:
Cash	$ 25,144	$ 17,433
Accounts receivable	35,302	32,263
Due from affiliates	9,319	3,734
Derivative instruments	42,482	32,683
Prepaid and other current assets	659	249
Total current assets	112,906	86,362
Noncurrent assets:
Evaluated	1,270,689	975,182
Unevaluated	9,000
Gross oil and natural gas properties	1,279,689	975,182
Gas processing equipment	4,110	865
Less accumulated depreciation, depletion and amortization	(141,912)	(80,484)
Total property and equipment, net	1,141,887	895,563
Derivative instruments	81,450	70,570
Deferred taxes		270
Other assets	11,408	4,279
Total noncurrent assets	1,234,745	970,682
Total assets	1,347,651	1,057,044
Current liabilities:
Current portion of asset retirement obligations	845	348
Derivative instruments	5,176	9,569
Accrued and other liabilities	60,182	50,027
Total current liabilities	66,203	59,944
Noncurrent liabilities:
Long-term debt	620,946	500,000
Derivative instruments	14,156	16,906
Asset retirement obligations	73,507	65,353
Other liabilities	6,755
Deferred taxes	102
Total noncurrent liabilities	715,466	582,259
Commitments and contingencies (see Note 11)
Partners' capital:
Class C convertible preferred unitholders (16,666,667 issued and outstanding as of September 30, 2012 and December 31, 2011)	369,278	358,138
General partner (41,747 and 35,729 units issued and outstanding as of September 30, 2012 and December 31, 2011)	614	546
Total partners' capital	565,982	414,841
Total liabilities and partners' capital	1,347,651	1,057,044
Limited Partners-Public Common [Member]
Partners' capital:
Limited partners' capital account	258,578	241,306
Limited Partners-Affiliated - Common [Member]
Partners' capital:
Limited partners' capital account		(113,414)
Limited Partners-Affiliated - Subordinated [Member]
Partners' capital:
Limited partners' capital account	$ (62,488)	$ (71,735)

XML

Derivative Activities (Fair Value Of Derivative Contracts) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]
Current asset derivatives	$ 42,482	$ 32,683
Noncurrent asset derivatives	81,450	70,570
Asset derivative instruments	123,932	103,253
Asset derivative instruments	123,932	103,253
Current liability derivatives	5,176	9,569
Noncurrent liability derivatives	14,156	16,906
Liability derivative instruments	19,332	26,475
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Current asset derivatives	42,482	32,683
Noncurrent asset derivatives	81,450	70,550
Asset derivative instruments	123,932	103,233
Asset derivative instruments	123,932	103,233
Current liability derivatives	565	1,284
Noncurrent liability derivatives	5,497	1,218
Liability derivative instruments	6,062	2,502
Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Noncurrent asset derivatives		20
Asset derivative instruments		20
Asset derivative instruments		20
Current liability derivatives	4,611	8,285
Noncurrent liability derivatives	8,659	15,688
Liability derivative instruments	$ 13,270	$ 23,973

XML

Consolidated Statements Of Cash Flows (Unaudited) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Cash flows from operating activities:
Net income	$ 46,883	$ 87,604
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	61,428	58,295
Accretion of asset retirement obligations	2,645	2,033
Recognition of unit-based awards	2,124	990
General and administrative expense contributed by affiliates	22,224	21,252
Unrealized gains on derivative contracts	(23,011)	(135,590)
Deferred income tax benefit	372	361
Other items	3,222	1,950
Changes in operating assets and liabilities:
Accounts receivable and other assets	(11,232)	(16,529)
Accounts payable and other liabilities	5,731	2,015
Net cash provided by operating activities	110,386	22,381
Cash flows from investing activities:
Additions to oil and gas properties	(80,566)	(43,917)
Proceeds from the sale of oil and gas properties	3,082	1,327
Acquisitions	(225,118)
Net cash used in investing activities	(302,602)	(42,590)
Cash flows from financing activities:
Proceeds from unit offering, net of offering costs	161,958	41,963
Proceeds from senior note offering, net of discount	295,860
Distributions to the Fund		(42,000)
Proceeds from issuance of units to the General Partner	115	715
Management incentive fee to the General Partner	(3,155)
Distributions to unitholders	(70,959)	(31,223)
Contributions from the Predecessor		8,985
Proceeds from bank borrowings	116,500	41,000
Repayments on bank borrowings	(291,500)
Deferred financing costs	(8,892)	(214)
Net cash provided by financing activities	199,927	19,226
Increase (decrease) in cash	7,711	(983)
Cash at beginning of period	17,433	2,195
Cash at end of period	$ 25,144	$ 1,212

XML

Unit-Based Compensation (Summary Of Unit-Based Awards) (Details) (Restricted Units [Member], USD $)	1 Months Ended	9 Months Ended
	Jul. 31, 2012	Sep. 30, 2012
Service Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested units, December 31, 2011		271,000
Granted, units	392,149	428,000
Forfeited, units		(35,000)
Vested, units		(18,000)
Unvested units, September 30, 2012		645,563
Weighted average grant date fair value, December 31, 2011		$ 20.33
Weighted average grant date fair value, granted		$ 18.18
Weighted average grant date fair value, forfeited		$ 20.23
Weighted average grant date fair value, vested		$ 20.16
Weighted average grant date fair value, September 30, 2012		$ 18.80
Performance Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested units, December 31, 2011
Granted, units		121,000
Forfeited, units
Vested, units
Unvested units, September 30, 2012		121,000
Weighted average grant date fair value, December 31, 2011
Weighted average grant date fair value, granted		$ 18.06
Weighted average grant date fair value, forfeited
Weighted average grant date fair value, vested
Weighted average grant date fair value, September 30, 2012		$ 18.06

XML

Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2012

Supplemental Cash Flow Information [Abstract]

Schedule Of Supplemental Cash Flow Information

		Nine Months Ended
		September 30, 2012		September 30, 2011
Supplemental Cash Flow Information
Cash paid during the period for interest	$	33,322	$	13,236
Non-cash Investing and Financing Activities
Change in accrued capital expenditures		(6,660)		2,165
Interest rate swaps novated from the Fund		-		2,875
General and administrative expense allocated from the Fund		22,224		21,252
Amortization of increasing rate distributions(1)		11,140		-

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

XML

Subsequent Events (Notional Volumes Of Commodity Derivative Contracts) (Details)	Oct. 31, 2012	Sep. 30, 2012
Oil Positions [Member] | 2013 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	627	6,543
Average price	88.20	99.75
Oil Positions [Member] | 2014 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	1,000	5,661
Average price	87.53	97.91
Oil Positions [Member] | 2014 [Member] | WTI [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		425
Average floor price		90.00
Average ceiling price		106.50
Oil Positions [Member] | 2015 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	931	4,540
Average price	85.65	96.87
Oil Positions [Member] | 2015 [Member] | WTI [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		1,025
Average floor price		90.00
Average ceiling price		110.00
Oil Positions [Member] | 2016 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	868	2,480
Average price	84.65	92.07
Oil Positions [Member] | 2016 [Member] | WTI [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		1,500
Average floor price		80.00
Average ceiling price		102.00
Oil Positions [Member] | 2017 [Member] | WTI [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	817	3,730
Average price	84.35	87.57
Natural Gas Positions [Member] | 2013 [Member] | Henry Hub [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	767
Average price	3.99
Natural Gas Positions [Member] | 2013 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		2,466
Average floor price		6.50
Average ceiling price		8.65
Natural Gas Positions [Member] | 2014 [Member] | Henry Hub [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	715
Average price	4.27
Natural Gas Positions [Member] | 2014 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		4,966
Average floor price		5.74
Average ceiling price		7.51
Natural Gas Positions [Member] | 2015 [Member] | Henry Hub [Member] | Swaps [Member]
Derivative [Line Items]
Hedged volume per day	671
Average price	4.43
Natural Gas Positions [Member] | 2015 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day		18,000
Average floor price		5.00
Average ceiling price		7.48
Natural Gas Positions [Member] | 2015 [Member] | Henry Hub [Member] | Put [Member]
Derivative [Line Items]
Hedged volume per day		420
Average price		4.0
Natural Gas Positions [Member] | 2016 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day	630
Average floor price	4.00
Average ceiling price	5.55
Natural Gas Positions [Member] | 2016 [Member] | Henry Hub [Member] | Put [Member]
Derivative [Line Items]
Hedged volume per day		11,350
Average price		4.0
Natural Gas Positions [Member] | 2017 [Member] | Henry Hub [Member] | Collars [Member]
Derivative [Line Items]
Hedged volume per day	595
Average floor price	4.00
Average ceiling price	6.15
Natural Gas Positions [Member] | 2017 [Member] | Henry Hub [Member] | Put [Member]
Derivative [Line Items]
Hedged volume per day		10,445
Average price		4.0

XML

Subsidiary Guarantors

9 Months Ended

Sep. 30, 2012

Subsidiary Guarantors [Abstract]

Subsidiary Guarantors

NOTE 16–SUBSIDIARYGUARANTORS

On June 1, 2012,wefiled a registration statement on Form S-3 with the SEC to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC.The Partnership’s Senior Notes, issued on July 30, 2012, are guaranteed by OLLC, a 100% owned subsidiary of the Partnership, and certain other future subsidiaries (the “Guarantor”, together with any future 100% owned subsidiaries that guarantee the Partnership’s Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned by the Partnership and the guarantees by the Subsidiaries are 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. The guarantees constitute joint and several obligations. Refer to Note 9 – Long-Term Debt for details on the conditions of guarantor releases.

XML

Subsequent Events (Tables)

9 Months Ended

Sep. 30, 2012

Subsequent Event [Line Items]

Notional Volumes Of Commodity Derivative Contracts

Commodity	Index		Oct 1 - Dec 31, 2012		2013		2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		5,872		6,543		5,661		4,540		2,480		3,730
Average price ($/Bbls)		$	100.34	$	99.75	$	97.91	$	96.87	$	92.07	$	87.57
Collars
Hedged Volume (Bbls/d)	WTI						425		1,025		1,500
Average floor price ($/Bbls)						$	90.00	$	90.00	$	80.00
Average ceiling price ($/Bbls)						$	106.50	$	110.00	$	102.00
Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		30,213		29,674		25,907		6,520		11,350		10,445
Average price ($/MMBtu)		$	5.89	$	6.07	$	6.23	$	5.43	$	4.27	$	4.47
Basis Swaps
Hedged Volume (MMBtu/d)	Henry Hub		20,709		18,466		17,066		14,400
Average price ($/MMBtu)		$	(0.15)	$	(0.17)	$	(0.19)	$	(0.19)
Collars
Hedged Volume (MMBtu/d)	Henry Hub		2,609		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
Puts
Hedged Volume (MMBtu/d)	Henry Hub								420		11,350		10,445
Average price ($/MMBtu)								$	4.00	$	4.00	$	4.00

Subsequent Event [Member]

Subsequent Event [Line Items]

Notional Volumes Of Commodity Derivative Contracts

Commodity	Index		2013		2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		627		1,000		931		868		817
Average price ($/Bbls)		$	88.20	$	87.53	$	85.65	$	84.65	$	84.35
Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		767		715		671
Average price ($/MMBtu)		$	3.99	$	4.27	$	4.43
Collars
Hedged Volume (MMBtu/d)	Henry Hub								630		595
Average floor price ($/MMBtu)								$	4.00	$	4.00
Average ceiling price ($/MMBtu)								$	5.55	$	6.15

XML

Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2012

Significant Accounting Policies [Abstract]

Basis Of Presentation

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles in the United States (“U.S. GAAP”) for complete annual financial statements. During interim periods, the Partnership follows the accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”), filed with the SEC. The unaudited consolidated financial statements for the three and ninemonths ended September 30, 2012 and 2011 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. Prior period amounts have been revised to conform to current period presentation. Operating results for the three and nine months ended September 30, 2012 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2012. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our 2011 Annual Report.

The Partnership’s historical financial statements previously filed with the SEC have been revised in this quarterly report on Form 10-Q 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 January 1, 2011 to September 30, 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 set forth in Note 2 of the Notes to Consolidated Financial Statements in our 2011 Annual Report.

Unevaluated Properties

Unevaluated Properties

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

Business Combinations

Business Combinations

We account for all business combinations using the purchase method, in accordance with U.S. GAAP. Under the purchase method of accounting, a business combination is accounted for at the 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. The difference between the fair value of assets acquired and liabilities assumed over the cost of the entity, if any, is recorded as either goodwill or a bargain purchase gain. The Partnership has not recognized any goodwill from business combinations.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04). The amendments in ASU 2011-04 are the result of the FASB's and the International Accounting Standards Board's (“IASB”) work to develop common requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP 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 amendment was adopted by us on January 1, 2012 and did not 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 instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a 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.

XML

Organization And Operations

9 Months Ended

Sep. 30, 2012

Organization And Operations [Abstract]

Organization And Operations

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 assets of the affiliated entity, QA Holdings, LP (the “Predecessor”) and own other assets. Certain of the Predecessor’s subsidiaries (collectively known as the “Fund”) include 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. Quantum Resources Management, LLC (“QRM”) provides management and operational services for us and the Fund. Our general partner is QRE GP, LLC (or “QRE GP”). We conduct our operations through our wholly owned subsidiary QRE Operating, LLC (“OLLC”). Our wholly owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities.

We completed our initial public offering of15,000,000 common units representing limited partner interests in the Partnership on December 22, 2010 (the “Closing Date”). 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. In exchange for the net assets, the Fund received 11,297,737 common and 7,145,866 subordinated limited partner units. QRE GP made a capital contribution to the Partnership in exchange for 35,729 general partner units.  The underwriters exercised their over-allotment option in full for 2,250,000 common units issued by the Partnership. Net proceeds from the sale of these common units, after deducting offering costs, were approximately $42 million.  

On October 3, 2011, the Fund sold certain oil and gas properties to the Partnership (the “Transferred Properties”) pursuant to a purchase and sale agreement by and among the Fund, the Partnership and OLLC in exchange for 16,666,667 Class C Convertible Preferred Units (“Preferred Units”) and the assumption of $227 million in debt (the “Transaction”).  The fair value of the Preferred Units on October 1, 2011 was $21.27 per unit or $354.5million with net assets of $252.0 million contributed to the Partnership by the Fund. The Transaction was accounted for as a transaction between entities under common control whereby the Transferred Properties were recorded at historical book value. As such, the value of the Preferred Units in excess of the net assets contributed by the Fund was deemed a $102.5 million distribution from the Partnership and allocated pro rata to the general partner and existing limited partners.

On April 17, 2012, we issued6,202,263 common units representing limited partnership interests in us, and the Fund sold 11,297,737of its common units it held in us (the “Equity Offering”), to the public pursuant to a registration statement filed with the Securities and Exchange Commission (the “SEC”).  In conjunction with the Equity Offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. Refer to Note 10 – Partners’ Capitalfor further details. Proceeds from the Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.

On April 20, 2012, we closed the acquisition of primarily oil properties from Prize Petroleum, LLC and Prize Petroleum Pipeline, LLC (collectively “Prize”) for approximately $225 million in cash(the “Prize Acquisition”), with an effective date of January 1, 2012.  Refer to Note 3 – Acquisitions for further details.

On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register the issuance and sale, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Note 16 – Subsidiary Guarantors for details.

On July 30, 2012, we and our wholly-owned subsidiary QRE FC, issued $300 million of 9.25% Senior Notes (the “Senior Notes”) due 2020.  On September 7, 2012, we filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes to exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012. The exchange of the Senior Notes was completed on November 7, 2012. Refer to Note 9 – Long-Term Debt for further details.

As ofSeptember 30, 2012, our ownership structure comprised a 0.1% general partner interest held by QRE GP, a38.8% limited partner interest held by the Fund, represented by all of our preferred and subordinated units, and a61.1% limited partner interest held by the public unitholders.

XML

Consolidated Balance Sheets (Unaudited) (Parenthetical)	Sep. 30, 2012	Dec. 31, 2011
Partners' capital:
Class C convertible preferred unitholders issued (in units)	16,666,667	16,666,667
Class C convertible preferred unitholders outstanding (in units)	16,666,667	16,666,667
General partner, issued (in units)	41,747	35,729
General partner, outstanding (in units)	41,747	35,729
Limited Partners-Public Common [Member]
Partners' capital:
Limited partners unitholders, issued (in units)	37,434,720	17,292,279
Limited partners unitholders, outstanding (in units)	37,434,720	17,292,279
Limited Partners-Affiliated - Common [Member]
Partners' capital:
Limited partners unitholders, issued (in units)	0	11,297,737
Limited partners unitholders, outstanding (in units)	0	11,297,737
Limited Partners-Affiliated - Subordinated [Member]
Partners' capital:
Limited partners unitholders, issued (in units)	7,145,866	7,145,866
Limited partners unitholders, outstanding (in units)	7,145,866	7,145,866

XML

Commitments And Contingencies

9 Months Ended

Sep. 30, 2012

Commitments And Contingencies [Abstract]

Commitments And Contingencies

NOTE11–COMMITMENTSANDCONTINGENCIES

Services Agreement

We have entered into a services agreement (the “Services Agreement”) with QRM as described in Note 14 – Related Party Transactions, under which QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined under the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee.  The Partnership had no other commitments as of September 30, 2012.

Legal Proceedings

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. 

Environmental Contingencies

As of September 30, 2012, we have approximately $1.9 million in environmental liabilities related to the Prize Acquisition. This is management’s best estimate of the costs for remediation and restoration with respect to these environmental matters, although the ultimate cost could increase materially. The environmental liability is recorded in the other liabilities caption on the consolidated balance sheet. Inherent uncertainties exist in these estimates primarily due to unknown conditions, changing governmental regulation and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration.

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2012	Nov. 08, 2012 Class C Convertible Preferred [Member]	Nov. 08, 2012 Limited Partners-Affiliated - Common [Member]	Nov. 08, 2012 Limited Partners-Affiliated - Subordinated [Member]	Nov. 08, 2012 General Partner [Member]
Entity Information [Line Items]
Entity Registrant Name	QR Energy, LP
Entity Central Index Key	0001502012
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Trading Symbol	qre
Entity Common Stock, Shares Outstanding		16,666,667	37,445,752	7,145,866	41,747
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2012

XML

Net Income/(Loss) Per Limited Partner Unit

9 Months Ended

Sep. 30, 2012

Net Income/(Loss) Per Limited Partner Unit [Abstract]

Net Income/Loss Per Limited Partner Unit

NOTE 12 – NET INCOME/(LOSS) PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income (loss) per limited partner unit for the three and nine months ended September 30, 2012 and September 30, 2011:

		Three Months Ended				Nine Months Ended
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
Net income (loss)	$	(45,007)	$	105,165	$	46,883	$	87,604
Net income (loss) attributable to predecessor operations		-		(53,235)		-		(49,091)
Distribution on Class C convertible preferred units		(3,500)		-		(10,500)		-
Amortization of preferred unit discount		(3,751)		-		(11,140)		-
Net income (loss) available to other unitholders		(52,258)		51,930		25,243		38,513
Less: general partner's interest in net income (loss)		3,705		52		6,150		39
Limited partners' interest in net income (loss)	$	(55,963)	$	51,878	$	19,093	$	38,474
Common unitholders' interest in net income (loss)	$	(46,930)	$	41,540	$	16,717	$	30,829
Subordinated unitholders' interest in net income (loss)	$	(9,033)	$	10,338	$	2,376	$	7,644
Net loss per limited partner unit:
Common unitholders' (basic)	$	(1.25)	$	1.45	$	0.49	$	1.07
Common unitholders' (diluted)		(1.25)		1.45		0.49		1.07
Subordinated unitholders' (basic)	$	(1.26)	$	1.45	$	0.33	$	1.07
Subordinated unitholders' (diluted)		(1.26)		1.45		0.33		1.07
Weighted average number of limited partner units outstanding (1):
Common units (basic)		37,425		28,713		34,347		28,698
Common units (diluted)		37,425		28,713		34,347		28,698
Subordinated units (basic and diluted)		7,146		7,146		7,146		7,146

⁽¹⁾ For the three and nine months ended September 30, 2012, we had weighted average preferred units outstanding of 16,666,667, which are contingently convertible.  These units could potentially dilute earnings per unit in the future and have not been included in the earnings per unit calculation for the three and nine months ended September 30, 2012, as they were anti-dilutive for the periods.

Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the limited partner unitholders, after deducting QRE GP’s 0.1% interest in net income (loss), by the weighted average number of limited partner units outstanding during the three and nine months ended September 30, 2012. We had 37,434,720 common units and 7,145,866 subordinated units outstanding as of September 30, 2012.

XML

Consolidated Statements Of Operations (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Revenues:
Oil and natural gas sales	$ 64,559		$ 64,289		$ 191,722		$ 193,969
Processing and other	410		492		1,243		1,523
Total revenues	64,969		64,781		192,965		195,492
Operating Expenses:
Production expenses	24,681		24,161		73,448		65,197
Depreciation, depletion and amortization	21,298		19,965		61,428		58,295
Accretion of asset retirement obligations	915		719		2,645		2,033
General and administrative	9,232		8,338		26,345		22,577
Acquisition and transaction costs	278				1,286
Total operating expenses	56,404		53,183		165,152		148,102
Operating income	8,565		11,598		27,813		47,390
Other income (expense):
Gain (losses) on commodity derivative contracts	(45,382)		98,741		37,904		53,435
Interest expense, net	11,533		19,950		28,398		39,161
Total other income (expense), net	(53,743)		94,356		19,598		41,148
Income (loss) before income taxes	(45,178)		105,954		47,411		88,538
Income tax benefit (expense), net	171		(789)		(528)		(934)
Net income (loss)	(45,007)		105,165		46,883		87,604
Weighted average number of limited partner units outstanding:
Subordinated units (basic and diluted) (in units)	7,146	[1]	7,146	[1]	7,146	[1]	7,146	[1]
Realized Gain (Loss) [Member]
Other income (expense):
Gain (losses) on commodity derivative contracts	(2,770)		(40,041)		14,893		(82,155)
Commodity Contract [Member]
Other income (expense):
Gain (losses) on commodity derivative contracts	(42,210)	[2]	114,306	[2]	47,996	[2]	80,309	[2]
Commodity Contract [Member] | Realized Gain (Loss) [Member]
Other income (expense):
Gain (losses) on commodity derivative contracts	13,375	[2]	(39,072)	[2]	35,668	[2]	(79,924)	[2]
Commodity Contract [Member] | Unrealized Gain (Loss) [Member]
Other income (expense):
Gain (losses) on commodity derivative contracts	$ (55,585)		$ 153,378		$ 12,328		$ 160,233
Limited Partners-Affiliated - Common [Member]
Net loss per limited partner unit:
Unitholders' (basic) (in dollars per unit)	$ (1.25)		$ 1.45		$ 0.49		$ 1.07
Unitholders' (diluted) (in dollars per unit)	$ (1.25)		$ 1.45		$ 0.49		$ 1.07
Weighted average number of limited partner units outstanding:
Common units (basic) (in units)	37,425	[1]	28,713	[1]	34,347	[1]	28,698	[1]
Common units (diluted) (in units)	37,425	[1]	28,713	[1]	34,347	[1]	28,698	[1]
Limited Partners-Affiliated - Subordinated [Member]
Net loss per limited partner unit:
Unitholders' (basic) (in dollars per unit)	$ (1.26)		$ 1.45		$ 0.33		$ 1.07
Unitholders' (diluted) (in dollars per unit)	$ (1.26)		$ 1.45		$ 0.33		$ 1.07

[1] For the three and nine months ended September 30, 2012, we had weighted average preferred units outstanding of 16,666,667, which are contingently convertible. These units could potentially dilute earnings per unit in the future and have not been included in the earnings per unit calculation for the three and nine months ended September 30, 2012, as they were anti-dilutive for the periods.

[2] Gain (loss) on commodity derivative contracts is located in other income (expense) in the consolidated statements of operations.

XML

Income Taxes

9 Months Ended

Sep. 30, 2012

Income Taxes [Abstract]

Income Taxes

NOTE 6 – INCOME TAXES

We do not pay federal income taxes as our profits or losses are reported to the taxing authorities by the individual partners.

Our income taxes are entirely attributable to the Texas Margin Tax which is derived from our taxable income apportioned to Texas. We recorded a deferred tax asset of $0.3 million and$0.3 million related to its operations located in Texas as of September 30, 2012 and December 31, 2011 and a deferred tax liability of $0.4 million and less than $0.1 million as of September 30, 2012 and December 31, 2011. The deferred tax asset and deferred tax liability are presented net as a deferred tax liability of $0.1 million on the consolidated balance sheet as of September 30, 2012 and as a deferred tax asset of $0.3 million on the consolidated balance sheet as of December 31, 2011. Our provision for income taxes was a net benefit of $0.2 million and a net expense of  $0.5 million for the three and nine months ended September 30, 2012 and a net expense of $0.8 million and $0.9 million for the three and nine months ended September 30, 2011.

XML

Derivative Activities

9 Months Ended

Sep. 30, 2012

Derivative Activities [Abstract]

Derivative Activities

NOTE 5 – DERIVATIVE ACTIVITIES

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 consolidated statements of operations.

Although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have presented all asset and liability positions without netting. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.  We do not post collateral under any of these contracts as they are secured under our credit facility.

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 fluctuations due to changes in the market price of oil and natural gas. We use derivatives to reduce our exposure to changes in the prices of oil and natural gas. Our policies do not permit the use of derivatives for speculative purposes.

During the nine months ended September 30, 2012, we entered into new oil swap contracts with settlement dates ranging from 2012 through 2017, natural gas put contracts, with deferred premiums, and swap contracts with settlement dates ranging from 2015 through 2017.  All of the new contracts were entered into with the same counterparties as our existing contracts.

The deferred premiums associated with certain of our oil and natural gas derivative instruments are  $4.9 million and are classified as other non-current liabilities on the consolidated balance sheet as ofSeptember 30, 2012.  There were no deferredderivative contract premiums at December 31, 2011. These deferred premiums will be paid to the counterparty with each monthly settlement (January 2015 – December 2017)  and recognized as an adjustment of realized gain (loss) on derivative instruments.

We hold commodity derivative contracts to manage our exposure to changes in the price of oil and natural gas related to our oil and natural gas production.  As of September 30, 2012, the notional volumes of our commodity derivative contracts were:

Commodity	Index		Oct 1 - Dec 31, 2012		2013		2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		5,872		6,543		5,661		4,540		2,480		3,730
Average price ($/Bbls)		$	100.34	$	99.75	$	97.91	$	96.87	$	92.07	$	87.57
Collars
Hedged Volume (Bbls/d)	WTI						425		1,025		1,500
Average floor price ($/Bbls)						$	90.00	$	90.00	$	80.00
Average ceiling price ($/Bbls)						$	106.50	$	110.00	$	102.00
Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		30,213		29,674		25,907		6,520		11,350		10,445
Average price ($/MMBtu)		$	5.89	$	6.07	$	6.23	$	5.43	$	4.27	$	4.47
Basis Swaps
Hedged Volume (MMBtu/d)	Henry Hub		20,709		18,466		17,066		14,400
Average price ($/MMBtu)		$	(0.15)	$	(0.17)	$	(0.19)	$	(0.19)
Collars
Hedged Volume (MMBtu/d)	Henry Hub		2,609		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
Puts
Hedged Volume (MMBtu/d)	Henry Hub								420		11,350		10,445
Average price ($/MMBtu)								$	4.00	$	4.00	$	4.00

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 LIBOR component on our outstanding variable rate debt.  The changes in the fair value of these instruments are recorded in current earnings.

On July 31, 2012, we terminated certain interest rate derivative contracts which were scheduled to expire at various times through the fourth quarter 2015 and recorded a $15 million realized loss for the early termination.

The fair value of our derivatives as recorded on our balance sheet was as follows as of the dates indicated:

		September 30, 2012				December 31, 2011
		Asset		Liability		Asset		Liability
		Derivatives		Derivatives		Derivatives		Derivatives
Commodity contracts	$	123,932	$	6,062	$	103,233	$	2,502
Interest rate contracts		-		13,270		20		23,973
	$	123,932	$	19,332	$	103,253	$	26,475
Commodity
Current	$	42,482	$	565	$	32,683	$	1,284
Noncurrent		81,450		5,497		70,550		1,218
	$	123,932	$	6,062	$	103,233	$	2,502
Interest
Current	$	-	$	4,611	$	-	$	8,285
Noncurrent		-		8,659		20		15,688
	$	-	$	13,270	$	20	$	23,973
Total Derivatives
Current	$	42,482	$	5,176	$	32,683	$	9,569
Noncurrent		81,450		14,156		70,570		16,906
	$	123,932	$	19,332	$	103,253	$	26,475

The following table presents the impact of derivatives and their location within our unaudited consolidated statements of operations for the three andninemonths ended September 30, 2012 and September 30, 2011:

		Three Months Ended				Nine Months Ended
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
Realized gains (losses):
Commodity contracts (1)	$	13,375	$	(39,072)	$	35,668	$	(79,924)
Interest rate swaps (2)		(16,145)		(969)		(20,775)		(2,231)
Total	$	(2,770)	$	(40,041)	$	14,893	$	(82,155)
Unrealized gains (losses):
Commodity contracts (1)	$	(55,585)	$	153,378	$	12,328	$	160,233
Interest rate swaps (2)		12,973		(14,596)		10,683		(24,643)
Total	$	(42,612)	$	138,782	$	23,011	$	135,590
Total gains (losses):
Commodity contracts (1)	$	(42,210)	$	114,306	$	47,996	$	80,309
Interest rate swaps (2)		(3,172)		(15,565)		(10,092)		(26,874)
Total	$	(45,382)	$	98,741	$	37,904	$	53,435

⁽¹⁾Gain (loss) on commodity derivative contracts is located in other income (expense) in the consolidated statements of operations.

⁽²⁾Gain (loss) on interest rate derivatives contracts is recorded as part of interest expense and is located in other income (expense) in the consolidated statements of operations.

XML

Subsequent Events

9 Months Ended

Sep. 30, 2012

Subsequent Events [Abstract]

Subsequent Events

NOTE 17 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after September 30, 2012,  through the issuance of the financial statements.

Revolving Credit Facility Redetermination

On October 30, 2012, we completed our semi-annual borrowing base redetermination which resulted in an increase in the borrowing base of our revolving credit facility from $655 million to $730 million. Refer to Note 9 – Long-Term Debt for further details.

Acquisition of Oil and Gas Properties

On October 26, 2012, we entered into a purchase and sale agreement with a private seller to purchase predominately oil and natural gas properties in the Ark-La-Tex area for approximately $215 million. The acquisition is expected to close in the fourth quarter of 2012.

Derivative Contracts

In October 2012, we entered into new oil and natural gas derivative contracts for the years 2013 through 2017. These contracts were entered into with the same counterparties as our existing derivative contracts. The table below details the newly executed contracts.

Commodity	Index		2013		2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		627		1,000		931		868		817
Average price ($/Bbls)		$	88.20	$	87.53	$	85.65	$	84.65	$	84.35
Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		767		715		671
Average price ($/MMBtu)		$	3.99	$	4.27	$	4.43
Collars
Hedged Volume (MMBtu/d)	Henry Hub								630		595
Average floor price ($/MMBtu)								$	4.00	$	4.00
Average ceiling price ($/MMBtu)								$	5.55	$	6.15

Cost Allocation Methodology

On November 6, 2012, QRE GP approved a methodology for allocating general and administrative costs incurred by QRM on behalf of the Partnership upon the expiration of the current Services Agreement on December 31, 2012. Refer to Note 14 – Related Party Transactions for further details.

Completion of Senior Notes Exchange Offer

On November 7, 2012, the exchange offer for the Senior Notes, pursuant to a Form S-4 filed with the SEC, was completed. Refer to Note 9 – Long-term Debt for details.

XML

Unit-Based Compensation

9 Months Ended

Sep. 30, 2012

Unit-Based Compensation [Abstract]

Unit-Based Compensation

NOTE 13 – UNIT-BASED COMPENSATION

The QRE GP, LLC Long-Term Incentive Plan (the “Plan”) was established for employees, officers, consultants and directors and consultants of QRE GP and 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 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.

Restricted Units

During 2012, we issued restricted stock units with a service condition (“Restricted Units”) and restricted units with a performance condition (“Performance Units”). The fair value of the restricted units is based on the closing price of our common units at the grant date.

Service Restricted Units

For Restricted Units, we recognize compensation expense using a straight-line amortization of the grant date fair value over the vesting period of the award. On July 25, 2012, we granted an additional 392,149 Restricted Units to employees of QRM with a grant date per unit value of $18.19. For the three and nine months ended September 30, 2012, we recognized compensation expense related to the outstanding awards of $1.4 million and $2.2 million. For the three and nine months ended September 30, 2011 we recognized compensation expense of $0.4 million and $1.0 million. As of September 30, 2012, we had 645,563 of Restricted Units outstanding with unrecognized grant date fair value compensation expense of $11.9 million, which we expect to be recognized over a weighted-average period of approximately 3 years. 

Performance Restricted Units.

In July 2012, we granted a target number of performance shares under a performance unit award agreement to members of our senior management. The performance awards will be earned over a three year period based on the Partnership’s performance relative to its peers, with details to be determined and approved by our board in accordance with the Plan.

At each reporting period, we will assess the probability of meeting the performance conditions to determine the final units to be issued for each Performance Unit and estimate compensation expense based on this probability. For the three and nine months ended September 30, 2012, we recognized compensation expense related to the Performance Units on a straight-line method within the Restricted Units until the performance conditions are approved. There were no Performance Units outstanding in 2011.

The following table summarizes our restricted unit-based awards for nine months endedSeptember 30, 2012:

		Weighted			Weighted
		Average			Average
	Number of	Grant-Date		Number of	Grant-Date
	Service Restricted units	Fair Value		Performance units	Fair Value
Unvested units, December 31, 2011	271	$	20.33	-	$	-
Granted	428		18.18	121		18.06
Forfeited	(35)		20.23	-		-
Vested	(18)		20.16	-		-
Unvested units, September 30, 2012	646	$	18.80	121	$	18.06

XML

Long-Term Debt

9 Months Ended

Sep. 30, 2012

Long-Term Debt [Abstract]

Long-Term Debt

NOTE 9 – LONG-TERM DEBT

As ofSeptember 30, 2012 and December 31, 2011, long-term consisted of (in thousands):

		September 30, 2012		December 31, 2011
Senior revolving credit facility	$	325,000	$	500,000
9.25% Senior Notes due 2020(1)		295,946		-
Total long-term debt	$	620,946	$	500,000

⁽¹⁾ The amount is net of unamortized discount of $4.1 million as of September 30, 2012.

Revolving Credit Facility

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

We entered into a Second Amendment to the Credit Agreement on March 16, 2012 to provide for additional derivative contracts to cover production of proved reserves to be acquired.

In April 2012, we entered into the Third Amendment to the Credit Agreement whereby increasing our credit facility from $750 million to $1.5 billion, increasing our borrowing base from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017. The Third Amendment became effective upon the closing of the Prize Acquisition. 

As a result of the issuance of the Senior Notes on July 30, 2012, our borrowing base was reduced by $75 million to $655 million from $730 million. On the same date, we made a payment on our outstanding borrowings under our revolving credit facility of $291.5 million using the cash proceeds from the Senior Notes issuance and cash on hand.  In connection with the reduction of the borrowing base, we wrote-off approximately $0.7 million of deferred loan costs associated with the Credit Agreement. On October 30, 2012, we were notified of an increase in our borrowing base, as part of our semi-annual borrowing base redetermination, from $655 million to the borrowing base prior to the issuance of the Senior Notes of$730 million.

As of September 30, 2012, we had $325.0 million of borrowings outstanding and $0.1 million of letters of credit outstanding resulting in $329.9 million of borrowing availability. As of December 31, 2011, we had $500.0 million of borrowings and $0.4 million letters of credit outstanding resulting in $129.6 million of borrowing availability.

As of November 8, 2012 we had $325.0 million of borrowings outstanding under our revolving credit facility and $404.9 million of borrowing availability.

As of September 30, 2012, the Credit Agreement provides for a five-year, $1.5 billion revolving credit facility maturing on April 20, 2017, with a borrowing base of approximately $655million. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ pricing assumptions, and other various factors unique to each member bank.The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. 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%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% 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 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum.

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 our 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 also requires us to provide audited financial statements within 90 days of year end and quarterly unaudited 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 our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reservesthereafter, 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 September 30, 2012, we were in compliance with all of the Credit Agreement covenants.

Bridge Loan Commitment

In conjunction with the Prize Acquisition, we entered into a secured commitment (the “Bridge Loan Commitment”) to provide an additional $200 million of bank loans to fund the acquisition as needed. We did not utilize any borrowings under the commitment and as of May 10, 2012 the Bridge Loan Commitment was terminated by us. We incurred $1.6 million of commitment fees related to the Bridge Loan Commitment which is recorded in interest expense for the nine months ended September 30, 2012.

9.25% Senior Notes

On July 30, 2012, we and our wholly-owned subsidiary QRE FC, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of our 9.25% Senior Notes, due 2020. The Senior Notes were issued at 98.62% of par. We received approximately $291.2 million of cash proceeds, net of the discount and underwriting fees, with total net proceeds of approximately  $290.2 million, after $1.0 million ofoffering costs. We used the net proceeds from the sale of the Senior Notes to repay borrowings outstanding under our credit facility. We will have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Our and QRE FC’s obligations under the Senior Notes are guaranteed by OLLC. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor’s, other, debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Note 16 – Subsidiary Guarantors for further details of our guarantors.

The indenture governing the Senior Notes (the “Indenture”) restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale-leaseback transactions; (ii) pay distributions on, or repurchase, equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.  The Indenture also includes customary events of default. The Partnership is in compliance with all financial and other covenants of the Senior Notes.

On September 7, 2012, we filed a registration statement on Form S-4 with the SEC to allow the holders of the Senior Notes to exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012. The exchange offer was completed on November 7, 2012.

XML

Related Party Transactions (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended			9 Months Ended					12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Sep. 30, 2012 QRE GP [Member]	Sep. 30, 2012 Fund [Member]	Sep. 30, 2012 General Partner [Member] QRE GP [Member]	Sep. 30, 2012 Limited Partner [Member] Fund [Member]	Sep. 30, 2012 Restricted Units [Member]	Dec. 31, 2011 Restricted Units [Member]	Sep. 30, 2012 Limited Partners-Affiliated - Common [Member]	Dec. 31, 2011 Limited Partners-Affiliated - Common [Member]
Related Party Transaction [Line Items]
General partner, outstanding (in units)	41,747		41,747		35,729	41,747
Predecessor's affiliate ownership of the GP						100.00%
Ownership percentage							38.80%	0.10%	38.80%
Limited partners unitholders, outstanding (in units)												0	11,297,737
Quarterly administration fee equal to percentage of adjusted EBITDA due to QRM			3.50%
Quarterly administration fee for QRM	$ 1,800,000	$ 700,000	$ 5,400,000	$ 800,000
General and administrative expense allocated from the Fund			22,224,000	21,252,000
Percentage of distribution equal or exceed minimum quarterly distributions			115.00%
Target distribution per unit			$ 0.4744
Percentage of quarterly management fee incentive base			0.25%
Management incentive fee incurred			6,100,000
Restricted unit awards granted										766,700	271,364
Restricted unit awards fair value										$ 14,400,000	$ 5,500,000

XML

Asset Retirement Obligations

9 Months Ended

Sep. 30, 2012

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

We record the asset retirement obligation (“ARO”) liability on our unaudited consolidated balance sheet and capitalize the cost in the “Oil and gas properties, using the full cost method of accounting” balance sheet caption during the period in which the obligation is incurred. We record the accretion of our ARO liabilities in “Accretion of asset retirement obligations” expense in our unaudited consolidated statements of operations. Payments to settle asset retirement obligations occur over the lives of the oil and gas properties. Revisions during the reporting period were due to changes in cost estimates for wells currently being retired.

Changes in our asset retirement obligations for ninemonths ended September 30, 2012 are presented in the following table:

		Nine Months Ended
		September 30, 2012
Beginning of period	$	65,701
Assumed in acquisition		4,738
Divested		(23)
Revisions to previous estimates		2,928
Liabilities incurred		1,208
Liabilities settled		(2,845)
Accretion expense		2,645
End of period	$	74,352
Less: Current portion of asset retirement obligations		(845)
Asset retirement obligations - non-current	$	73,507

XML

Accrued And Other Liabilities

9 Months Ended

Sep. 30, 2012

Accrued And Other Liabilities [Abstract]

Accrued And Other Liabilities

NOTE 8 – ACCRUED AND OTHER LIABILITIES

As of September 30, 2012 and December 31, 2011, we had the following accrued and other liabilities:

		September 30, 2012		December 31, 2011
Distributions payable	$	25,628	$	20,545
Accrued capital spending		2,931		9,591
Production expense accrual		16,925		12,872
Senior notes interest accrual		4,625		-
Management incentive fee		4,538		1,572
Other		5,535		5,447
	$	60,182	$	50,027

XML

Partners' Capital

9 Months Ended

Sep. 30, 2012

Partners' Capital [Abstract]

Partners' Capital

NOTE 10 — PARTNERS’ CAPITAL

Units Outstanding

The table below details the units outstanding as of September 30, 2012 and December 31, 2011, and the changes in outstanding units for the nine months ended September 30, 2012.  As of September 30, 2012, the Fund owned all preferred units and all subordinated units.

	Preferred Units	General Partner	Public Common	Affiliated Common	Subordinated
Balance - December 31, 2011	16,666,667	35,729	17,292,279	11,297,737	7,145,866
Vested units awarded under our Long Term Incentive
Performance Plan	-	-	18,359	-	-
Reduction in units to cover individuals' tax withholdings	-	-	(918)	-	-
Issuance of units to General Partner	-	6,018	-	-	-
Affiliated unit sale to the public	-	-	11,297,737	(11,297,737)	-
Unit offering	-	-	8,827,263	-	-
Balance - September 30, 2012	16,666,667	41,747	37,434,720	-	7,145,866

On April 17, 2012, we issued6,202,263 common units representing limited partnership interests in us, and the Fund sold11,297,737of its common units it held in us to the public pursuant to a registration statement filed with the SEC.  In conjunction with the Equity Offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. Proceeds from the Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.

On April 25, 2012, QRE GP purchased 6,018 general partner units in order to maintain its0.1% ownership percentage in us. The units were purchased at a price of $19.18 per unit.

On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Note 16 – Subsidiary Guarantors for details

Allocations of Net Income (Loss)

Net income (loss) is allocated to the preferred unitholders to the extent distributions are made or accrued to them during the period, to QRE GP to the extent of the management incentive fee, 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 Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in our Credit Agreement, occurs or would result from the cash distribution.

Our partnership agreement, as amended, 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.

As of September 30, 2012, QRE GP owns a 0.1% general partner interest in us, represented by 41,747 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 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.

Distribution activities are as follows:

						Limited Partners
							Affiliated
Payment Date	For the period ended	Distributions to Preferred Unitholders		Distributions per Preferred Unit(1)	General Partner	Public Common	Common	Subordinated	Total Distributions to Other Unitholders	Distributions per other units
(In thousands, except per unit amounts)
February 10, 2012	December 31, 2011	3,424	$	0.2054	16	8,344	5,368	3,393	17,121	0.4750
May 11, 2012	March 31, 2012	3,500	$	0.21	20	17,892	-	3,394	21,306	0.4750
August 10, 2012	June 30, 2012	3,500	$	0.21	20	18,584	-	3,484	22,088	0.4875
November 9, 2012	September 30, 2012	3,500	$	0.21	20	18,624	-	3,484	22,128	0.4875

(1) Preferred units paid in February 2012 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.

On September 28, 2012, the board of directors of QRE GP declared a $0.4875 per unit cash distribution for the third quarter 2012 whichis payable on November 9, 2012 to unitholders of record at the close of business on October 29, 2012.  The aggregate amount of the third quarter common and preferred unit holder distribution accrued, as of September 30, 2012,  was $25.6million.

XML

Subsequent Events (Details) (USD $) In Millions, unless otherwise specified	Oct. 28, 2012	Oct. 26, 2012	Oct. 30, 2012 Revolving Credit Facility [Member]	Sep. 30, 2012 Revolving Credit Facility [Member]	Jul. 30, 2012 Revolving Credit Facility [Member]	Apr. 11, 2012 Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Credit Agreement, current borrowing capacity			$ 730.0	$ 730.0	$ 655.0	$ 630.0
Approximate cash payment for oil and gas properties in Akr-La- Tex region	$ 215	$ 215

XML

Subsidiary Guarantors (Details)	9 Months Ended
	Sep. 30, 2012
Subsidiary Guarantors [Abstract]
Percentage ownership in Subsidiaries	100.00%

XML

Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2012

Related Party Transactions [Abstract]

Changes In The Affiliate Payable/Receivables Balance

Net affiliate receivable as of December 31, 2011		3,734
Revenues and other increases		187,036
Expenditures		(155,351)
Settlements from the Fund		(26,100)
Net affiliate receivable as of September 30, 2012	$	9,319

XML

Long-Term Debt (Schedule Of Long-Term Debt) (Details) (USD $)	9 Months Ended
	Sep. 30, 2012	Jul. 30, 2012	Dec. 31, 2011	Nov. 08, 2012 Revolving Credit Facility [Member]	Sep. 30, 2012 Revolving Credit Facility [Member]	Dec. 31, 2011 Revolving Credit Facility [Member]	Sep. 30, 2012 Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior revolving credit facility				$ 325,000,000	$ 325,000,000	$ 500,000,000
9.25% Senior Notes due 2020							295,946,000	[1]
Total long-term debt	620,946,000		500,000,000
Senior notes stated interest rate		9.25%
Senior notes maturity date	Nov. 30, 2020
Senior notes unamortized discount	$ 4,100,000

[1] The amount is net of unamortized discount of $4.1 million as of September 30, 2012.

XML

Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2012

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

NOTE 15 – SUPPLEMENTAL CASH FLOW INFORMATION

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

		Nine Months Ended
		September 30, 2012		September 30, 2011
Supplemental Cash Flow Information
Cash paid during the period for interest	$	33,322	$	13,236
Non-cash Investing and Financing Activities
Change in accrued capital expenditures		(6,660)		2,165
Interest rate swaps novated from the Fund		-		2,875
General and administrative expense allocated from the Fund		22,224		21,252
Amortization of increasing rate distributions(1)		11,140		-

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

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Measurements [Abstract]

Schedule Of Fair Value Of Financial Assets And Liabilities By Level

As of September 30, 2012		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	123,932	$	-	$	123,932	$	-
	$	123,932	$	-	$	123,932	$	-
Liabilities from commodity derivative instruments	$	6,062	$	-	$	6,062	$	-
Liabilities from interest rate derivative instruments		13,270		-		13,270		-
	$	19,332	$	-	$	19,332	$	-
As of December 31, 2011		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	103,233	$	-	$	103,233	$	-
Assets from interest rate derivative instruments		20		-		20		-
	$	103,253	$	-	$	103,253	$	-
Liabilities from commodity derivative instruments	$	2,502	$	-	$	2,502	$	-
Liabilities from interest rate derivative instruments		23,973		-		23,973		-
	$	26,475	$	-	$	26,475	$	-

XML

Accrued And Other Liabilities (Schedule Of Accrued And Other Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Accrued And Other Liabilities [Abstract]
Distributions payable	$ 25,628	$ 20,545
Accrued capital spending	2,931	9,591
Production expense accrual	16,925	12,872
Senior notes interest accrual	4,625
Management incentive fee	4,538	1,572
Other	5,535	5,447
Accrued and other liabilities	$ 60,182	$ 50,027

XML

Fair Value Measurements (Narrative) (Details) (Senior Notes due 2020 [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2012
Senior Notes due 2020 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair value of Senior Notes	$ 304.9
9.25% Senior Notes due 2020	$ 304.9

XML

Consolidated Statement Of Changes In Partners' Capital (Unaudited) (USD $) In Thousands	Limited Partners-Affiliated - Common [Member] Limited Partner [Member] Limited Partners-Public Common [Member]	Limited Partners-Affiliated - Common [Member] Limited Partner [Member]	Class C Convertible Preferred [Member]	General Partner [Member]	Limited Partner [Member] Limited Partners-Public Common [Member]	Limited Partner [Member] Limited Partners-Affiliated - Common [Member]	Limited Partner [Member] Limited Partners-Affiliated - Subordinated [Member]	Total
Balances at Dec. 31, 2011			$ 358,138					$ 414,841
Amortization of discount on increasing rate distributions			11,140					11,140
Balances at Jun. 30, 2012
Balances at Dec. 31, 2011			358,138	546	241,306	(113,414)	(71,735)	414,841
Contributions from the Predecessor						4,985	17,239	22,224
Proceeds from unit offering	(113,325)	113,325			161,958			161,958
Units issued to the General Partner				115				115
Recognition of unit-based awards					2,125			2,125
Reduction in units to cover individuals' tax withholding					(21)			(21)
Distributions to unitholders			(10,500)	(60)	(55,100)		(10,362)	(76,022)
Noncash distribution to preferred unitholders			(11,140)					(11,140)
Management incentive fee earned				(6,121)				(6,121)
Net income			21,640	6,134	21,635	(4,896)	2,370	46,883
Balances at Sep. 30, 2012			$ 369,278	$ 614	$ 258,578		$ (62,488)	$ 565,982

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2012

Fair Value Measurements [Abstract]

Fair Value Measurements

NOTE 4 – FAIR VALUE MEASURMENTS

Our financial instruments, including cash, 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). U.S. 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 requires an entity to develop its own assumptions for the asset or liability.

Commodity Derivative Instruments — The fair value of the commodity derivative instruments is estimated using a combined income and market valuation methodology based upon observable forward commodity price and volatility curves. The curves are obtained from independent pricing services.  We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

Interest Rate Derivative Instruments — The fair value of the interest rate derivative instruments is estimated using a combined income and market valuation methodology based upon observable forward interest rates and volatility curves. The curves are obtained from independent pricing services. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

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 September 30, 2012 and December 31, 2011. All fair values reflected below and on the consolidated balance sheet have been adjusted for nonperformance risk.

As of September 30, 2012		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	123,932	$	-	$	123,932	$	-
	$	123,932	$	-	$	123,932	$	-
Liabilities from commodity derivative instruments	$	6,062	$	-	$	6,062	$	-
Liabilities from interest rate derivative instruments		13,270		-		13,270		-
	$	19,332	$	-	$	19,332	$	-
As of December 31, 2011		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	103,233	$	-	$	103,233	$	-
Assets from interest rate derivative instruments		20		-		20		-
	$	103,253	$	-	$	103,253	$	-
Liabilities from commodity derivative instruments	$	2,502	$	-	$	2,502	$	-
Liabilities from interest rate derivative instruments		23,973		-		23,973		-
	$	26,475	$	-	$	26,475	$	-

Fair Value of Other Financial Instruments

Fair value guidance requires certain fair value disclosures, such as those on our long-term debt, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

Revolving Credit Facility — The fair value of our long term debt depends primarily on the current active market LIBOR. The carrying value of our long term debt as of September 30, 2012 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.

Derivative Premiums – The fair value of the deferred premiums on our commodity derivatives is based on the current active market LIBOR.  The carrying value of the premiums as of September 30, 2012 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.  Refer to Note 5 – Derivative Activities for further information on the derivative premiums.

Senior Notes – The fair value of the Senior Notes is measured based on inputs from quoted, unadjusted prices from over-the-counter markets for debt instruments. If the Senior Notes had been measured at fair value, we would classify them as Level 1 under the fair value hierarchy.The fair value of the Senior Notes as of September 30, 2012 was $304.9 million.

There have been no transfers between levels within the fair value measurement hierarchy during the nine months endedSeptember 30, 2012.

XML

Unit-Based Compensation (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended	3 Months Ended		9 Months Ended
	Jul. 31, 2012	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common unit awards authorized		1,800,000		1,800,000
Service Unit [Member] | Restricted Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted common units awarded to employees	392,149			428,000
Price per restricted common unit awarded to employees	$ 18.19
Compensation expense		$ 1.4	$ 0.4	$ 2.2	$ 1.0
Unvested units, December 31, 2011				271,000
Restricted unit awards outstanding		645,563		645,563
Restricted unit awards unamortized grant date fair value		$ 11.9		$ 11.9
Weighted average amortization period of grant date fair value, years				3 years
Performance Unit [Member] | Restricted Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted common units awarded to employees				121,000
Unvested units, December 31, 2011
Restricted unit awards outstanding		121,000		121,000

XML

Derivative Activities (Tables)

9 Months Ended

Sep. 30, 2012

Derivative Activities [Abstract]

Notional Volumes Of Commodity Derivative Contracts

Commodity	Index		Oct 1 - Dec 31, 2012		2013		2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		5,872		6,543		5,661		4,540		2,480		3,730
Average price ($/Bbls)		$	100.34	$	99.75	$	97.91	$	96.87	$	92.07	$	87.57
Collars
Hedged Volume (Bbls/d)	WTI						425		1,025		1,500
Average floor price ($/Bbls)						$	90.00	$	90.00	$	80.00
Average ceiling price ($/Bbls)						$	106.50	$	110.00	$	102.00
Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		30,213		29,674		25,907		6,520		11,350		10,445
Average price ($/MMBtu)		$	5.89	$	6.07	$	6.23	$	5.43	$	4.27	$	4.47
Basis Swaps
Hedged Volume (MMBtu/d)	Henry Hub		20,709		18,466		17,066		14,400
Average price ($/MMBtu)		$	(0.15)	$	(0.17)	$	(0.19)	$	(0.19)
Collars
Hedged Volume (MMBtu/d)	Henry Hub		2,609		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
Puts
Hedged Volume (MMBtu/d)	Henry Hub								420		11,350		10,445
Average price ($/MMBtu)								$	4.00	$	4.00	$	4.00

Fair Value Of Derivative Contracts

		September 30, 2012				December 31, 2011
		Asset		Liability		Asset		Liability
		Derivatives		Derivatives		Derivatives		Derivatives
Commodity contracts	$	123,932	$	6,062	$	103,233	$	2,502
Interest rate contracts		-		13,270		20		23,973
	$	123,932	$	19,332	$	103,253	$	26,475
Commodity
Current	$	42,482	$	565	$	32,683	$	1,284
Noncurrent		81,450		5,497		70,550		1,218
	$	123,932	$	6,062	$	103,233	$	2,502
Interest
Current	$	-	$	4,611	$	-	$	8,285
Noncurrent		-		8,659		20		15,688
	$	-	$	13,270	$	20	$	23,973
Total Derivatives
Current	$	42,482	$	5,176	$	32,683	$	9,569
Noncurrent		81,450		14,156		70,570		16,906
	$	123,932	$	19,332	$	103,253	$	26,475

Gains (Losses) Of Derivative Contacts By Statement Of Operations Location

		Three Months Ended				Nine Months Ended
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
Realized gains (losses):
Commodity contracts (1)	$	13,375	$	(39,072)	$	35,668	$	(79,924)
Interest rate swaps (2)		(16,145)		(969)		(20,775)		(2,231)
Total	$	(2,770)	$	(40,041)	$	14,893	$	(82,155)
Unrealized gains (losses):
Commodity contracts (1)	$	(55,585)	$	153,378	$	12,328	$	160,233
Interest rate swaps (2)		12,973		(14,596)		10,683		(24,643)
Total	$	(42,612)	$	138,782	$	23,011	$	135,590
Total gains (losses):
Commodity contracts (1)	$	(42,210)	$	114,306	$	47,996	$	80,309
Interest rate swaps (2)		(3,172)		(15,565)		(10,092)		(26,874)
Total	$	(45,382)	$	98,741	$	37,904	$	53,435

⁽¹⁾Gain (loss) on commodity derivative contracts is located in other income (expense) in the consolidated statements of operations.

⁽²⁾Gain (loss) on interest rate derivatives contracts is recorded as part of interest expense and is located in other income (expense) in the consolidated statements of operations.

XML

Acquisitions (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended				3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Oct. 28, 2012	Oct. 26, 2012	Sep. 30, 2012 Prize [Member]	Sep. 30, 2012 Prize [Member]	Apr. 20, 2012 Prize [Member]	Dec. 31, 2011 Prize [Member]
Business Acquisition [Line Items]
Date of acquisition								Apr. 20, 2012
Cash paid for acquisition									$ 225,000,000
Effective date of acquisition								Jan. 01, 2012
Estimated proved reserves (BOE)										13,300,000
Cost associated with acquisition recorded in acquisition and transaction costs								1,000,000
Estimated environmental liability							1,900,000	1,900,000	1,891,000
Revenue	64,969,000	64,781,000	192,965,000	195,492,000			8,700,000	15,200,000
Operating expenses	56,404,000	53,183,000	165,152,000	148,102,000			3,400,000	6,100,000
Approximate cash payment for oil and gas properties in Akr-La- Tex region					$ 215,000,000	$ 215,000,000

XML

Related Party Transactions

9 Months Ended

Sep. 30, 2012

Related Party Transactions [Abstract]

Related Party Transactions

Note 14 – RELATED PARTY TRANSACTIONS

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

As of September 30, 2012, affiliates of the Fund owned 100% of QRE GP, an aggregate38.8% limited partner interest in us represented by all of our preferred and subordinated units. In addition, QRE GP owned a 0.1% general partner interest in us, represented by 41,747 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 the activity of those agreements.

Services Agreement

Under the Services Agreement, until December 31, 2012, QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined under the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee. For the three and nine months ended September 30, 2012 we were charged $1.8 million and $5.4 million and for the three and nine months ended September 30, 2011, we were charged$0.7 million and  $0.8 million in administrative services fees in accordance with the Services Agreement.We will reimburse QRE GP for such payments it makes to QRM.

Beginning on January 1, 2013, QRM will be entitled to a quarterly administrative services fee based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. The fee will include direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If the Fund raises a second fund, the quarterly administrative services costs will be further divided to include the second fund as well. The allocation methodology was developed with the assistance of a third-party consultant with extensive experience in this area. These fees will be included in general and administrative expenses in our consolidated statement of operations. QRM will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.

 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 receivable balances during nine months endedSeptember 30, 2012 from the year ended December 31, 2011 are included below:

Net affiliate receivable as of December 31, 2011		3,734
Revenues and other increases		187,036
Expenditures		(155,351)
Settlements from the Fund		(26,100)
Net affiliate receivable as of September 30, 2012	$	9,319

Other Contributions to Partners’ Capital

Other contributions to partners’ capital for the ninemonths ended September 30, 2012 include non-cash general and administrative expense of $22.2 million contributed by the Fund, which represents our share of allocable general and administrative expenses incurred by QRM on our behalf but not reimbursable by us.

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 nine months ended September 30, 2012, the management incentive fee earned by QRE GP was $6.1 million.  For the nine months ended September 30, 2011, no management incentive fee was earned by or paid to our general partner.

Lease Guarantees

The Fund has entered into various lease contracts that can routinely extend beyond five years which list the Partnership as a guarantor. 

Long–Term Incentive Plan

The Plan provides compensation to employees, officers, consultants and directors of QRE GP and those of its affiliates, including QRM, who perform services for us. As of September 30, 2012 and December 31, 2011,  766,700 and 271,364restricted units with a grant date fair value of $14.4 million and $5.5 million were outstanding under the Plan. For additional discussion regarding the Plan see Note 13 – Unit-Based Compensation.

Distributions of Available Cash to QRE GP and Affiliates

We generally make cash distributions to our common and subordinated unitholders pro rata, including QRE GP and its affiliates. The Partnership paid a cash distribution on May 11, 2012 and August 31, 2012 for the quarters ended March 31, 2012 and June 30, 2012 and declared a third quarter 2012 distribution payable on November9, 2012.  Refer to Note 10 – Partners’ Capital for details on the distributions.

Our Relationship with Bank of America

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