QR Energy, LP - FORM 10-Q - November 14, 2011

Attached files

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EX-31.1 - EXHIBIT 31.1 - QR Energy, LP	ex31_1.htm
EX-32.1 - EXHIBIT 32.1 - QR Energy, LP	ex32_1.htm
EX-32.2 - EXHIBIT 32.2 - QR Energy, LP	ex32_2.htm
EX-31.2 - EXHIBIT 31.2 - QR Energy, LP	ex31_2.htm
EXCEL - IDEA: XBRL DOCUMENT - QR Energy, LP	Financial_Report.xls

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, 2011

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). o 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 o	Non-accelerated filer þ	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 12, 2011, there were 16,666,667 Class C Convertible Preferred Units, 28,565,344 Common Units, 7,145,866 Subordinated Units and 35,729 General Partner Units outstanding.

PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	4
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010	4
	Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010	5
	Consolidated Statement of Changes in Partners' Capital for the Nine Months Ended September 30, 2011	6
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010	7
	Notes to Consolidated Financials Statements	8

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	35

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3.	Defaults Upon Senior Securities	36
Item 4.	(Removed and Reserved)	36
Item 5.	Other Information	36
Item 6.	Exhibits	37

Signatures		38

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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 and natural gas 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, 2010 and the other disclosures contained herein and therein, which describe 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;

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

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

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;

the material weakness in our internal control over financial reporting;

actions of third party co-owners of interest 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

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this document and speak only as of the date of this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

QR ENERGY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(In thousands, except per unit amounts)

	Partnership			Predecessor			Partnership			Predecessor
	Three months ended September 30, 2011			Three months ended September 30, 2010			Nine months ended September 30, 2011			Nine months ended September 30, 2010
Revenues:
Oil, natural gas and natural gas liquids sales	$	28,491		$	81,659		$	90,439		$	168,516
Processing and other		217			2,819			689			6,954
Total revenues		28,708			84,478			91,128			175,470
Operating expenses:
Production expenses		10,927			31,299			28,478			68,556
Depreciation, depletion and amortization		7,832			25,908			25,043			45,149
Accretion of asset retirement obligations		308			1,193			865			2,648
Management fees		-			2,915			-			7,885
Acquisition evaluation costs		-			155			-			1,197
General and administrative and other		4,092			8,547			10,869			19,177
Bargain purchase gain		-			1,020			-			-
Total operating expenses		23,159			71,037			65,255			144,612
Operating income		5,549			13,441			25,873			30,858
Other income (expense):
Equity in earnings of Ute Energy, LLC		-			782			-			1,490
Realized gains (losses) on commodity derivative instruments		3,581			2,219			(37,271	)		5,132
Unrealized gains (losses) on commodity derivatives instruments		53,172			(3,501	)		69,904			41,432
Gain on equity share issuance		-			4,064			-			4,064
Interest expense, net		(10,097	)		(18,481	)		(19,627	)		(31,365	)
Other income (expense)		-			2			-			(407	)
Total other income (expense), net		46,656			(14,915	)		13,006			20,346
Income (loss) before income taxes		52,205			(1,474	)		38,879			51,204
Income tax expense		(275	)		(12	)		(366	)		(223	)
Net income (loss)		51,930			(1,486	)		38,513			50,981
Less: net (loss) income attributable to noncontrolling interest		-			(1,389	)		-			45,817
Net income (loss) attributable to controlling interest	$	51,930		$	(97	)	$	38,513		$	5,164
Less: general partner's interest in net income		52						39
Limited partners' interest in net income	$	51,878					$	38,474
Common unitholders' interest in net income	$	41,540					$	30,829
Subordinated unitholders' interest in net income	$	10,338					$	7,645
Net income per limited partner unit:
Common unitholders' (basic and diluted)	$	1.45					$	1.07
Subordinated unitholders' (basic and diluted)	$	1.45					$	1.07
Weighted-average limited partner units outstanding:
Common units (basic and diluted)		28,713						28,698
Subordinated units (basic and diluted)		7,146						7,146

See accompanying notes to consolidated financial statements

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QR ENERGY, LP

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(In thousands, except unit amounts)

	Partnership
	September 30, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	1,212		$	2,195
Accounts receivable: oil and gas sales		13,583			3,014
Due from affiliate		6,479			-
Due from general partner		-			715
Derivative instruments		21,305			9,027
Prepaid and other current assets		413			1,264
Total current assets		42,992			16,215
Noncurrent assets:
Oil and gas properties, using the full cost method of accounting		460,987			444,710
Less: accumulated depreciation, depletion and amortization		(25,956	)		(913	)
Total property and equipment, net		435,031			443,797
Derivative instruments		40,139			9,020
Deferred taxes		-			341
Other assets (See Note 6)		10,905			2,645
Total noncurrent assets		486,075			455,803
Total assets	$	529,067		$	472,018

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Due to affiliate	$	-		$	442
Current portion of asset retirement obligations		1,686			1,848
Derivative instruments		6,412			7,045
Accrued and other liabilities		8,054			3,806
Total current liabilities		16,152			13,141
Noncurrent liabilities:
Long-term debt		266,000			225,000
Derivative instruments		11,375			19,832
Asset retirement obligations		17,304			16,440
Deferred taxes		20			-
Total noncurrent liabilities		294,699			261,272
Commitments and contingencies (See Note 10)
Partners' capital:
General partner (35,729 units issued and outstanding as of September 30, 2011 and December 31, 2010)		715			708
Public common unitholders (17,267,607 and 15,000,000 units issued and outstanding as of September 30, 2011 and December 31, 2010)		323,270			276,723
Affiliated common unitholders (11,297,737 units issued and outstanding as of September 30, 2011 and December 31, 2010)		(64,790	)		(48,898	)
Subordinated unitholders (7,145,866 units issued and outstanding as of September 30, 2011 and December 31, 2010)		(40,979	)		(30,928	)
Total partners' capital		218,216			197,605
Total liabilities and partners' capital	$	529,067		$	472,018

See accompanying notes to consolidated financial statements

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QR ENERGY, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL

(UNAUDITED)

(In thousands)

				Limited Partners
	General			Public			Affiliated						Total
	Partner			Common			Common			Subordinated			Partners' Capital
Balances - December 31, 2010	$	708		$	276,723		$	(48,898	)	$	(30,928	)	$	197,605
Proceeds from over-allotment		-			41,963			-			-			41,963
Other contributions from the Fund (See Note 13)		-			-			7,575			4,793			12,368
Recognition of unit-based awards (See Note 12)		-			990			-			-			990
Distribution to the Fund		-			-			(25,727	)		(16,273	)		(42,000	)
Distributions to unitholders		(32	)		(15,149	)		(9,826	)		(6,216	)		(31,223	)
Net income		39			18,743			12,086			7,645			38,513
Balances - September 30, 2011	$	715		$	323,270		$	(64,790	)	$	(40,979	)	$	218,216

See accompanying notes to consolidated financial statements

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QR ENERGY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(In thousands)

	Partnership			Predecessor
	Nine months ended September 30, 2011			Nine months ended September 30, 2010
Cash flows from operating activities:
Net income	$	38,513		$	50,981
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		25,043			45,149
Accretion of asset retirement obligations		865			2,648
Amortization of deferred financing costs		430			2,042
Recognition of unit-based awards		990			-
Loss on disposal of furniture, fixtures and equipment		-			575
General and administrative expense contributed by the Fund		9,544			-
Unrealized gains on derivative contracts (See Note 4)		(58,363	)		(23,238	)
Deferred income tax expense		361			-
Equity in earnings of Ute Energy, LLC		-			(1,490	)
Gain on equity share issuance		-			(4,064	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		(16,415	)		(32,698	)
Accounts payable and other liabilities		2,520			10,857
Net cash provided by operating activities		3,488			50,762
Cash flows from investing activities:
Additions to oil and gas properties		(16,039	)		(33,653	)
Acquisition of oil and gas properties		-			(895,922	)
Additions of furniture, equipment and other		-			(1,469	)
Proceeds from the sale of oil and gas leases		1,327			-
Net cash used in investing activities		(14,712	)		(931,044	)
Cash flows from financing activities:
Proceeds from over-allotment (See Note 1)		41,963			-
Distribution to the Fund (See Note 1)		(42,000	)		-
Contributions from general partner		715			453,054
Distributions to unitholders		(31,223	)		(17,820	)
Proceeds from bank borrowings		41,000			574,752
Repayments on bank borrowings		-			(113,534	)
Deferred financing costs		(214	)		(11,986	)
Net cash provided by financing activities		10,241			884,466
(Decrease) increase in cash and cash equivalents		(983	)		4,184
Cash and cash equivalents at beginning of period		2,195			17,156
Cash and cash equivalents at end of period	$	1,212		$	21,340

(See Supplemental Cash Flow Information in Note 14)

See accompanying notes to consolidated financial statements

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QR ENERGY, LP

Notes to Consolidated 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 an affiliated entity, QA Holdings, LP (the “Predecessor”) and own and exploit producing oil and natural gas properties in North America. Certain of the Predecessor’s subsidiary limited partnerships (collectively known as the “Fund”), comprise Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC. 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”).

On December 22, 2010 (the “Closing Date”), we completed our initial public offering (“IPO”) of 15,000,000 common units representing limited partner interests in the Partnership at $20.00 per common unit. Total net proceeds from the sale of the common units in the IPO were $279.8 million ($300.0 million gross proceeds less $19.5 million underwriters’ discount and $0.7 million structuring fee). IPO related costs and expenses totaling $5.1 million were borne entirely by the Fund.

On the Closing Date, we also entered into the following agreements and transactions with the Fund:

Contribution Agreement and Concurrent Transactions

A Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) was executed on the Closing Date by and among the Fund, the Partnership and QRE GP with net assets contributed by the Fund to the Partnership as follows:

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

(1)

Novation of derivative instruments from the Fund to the Partnership was concurrent with the IPO but not part of the Contribution Agreement and such derivative instruments were transferred at fair value on the Closing Date. The fair value is reflected in the Predecessor’s book value by the means of non-recurring valuation measurements as of the date of transfer.

In exchange for the net assets above, the Fund received 11,297,737 common and 7,145,866 subordinated limited partner units and a $300.0 million cash distribution. QRE GP made a capital contribution of $0.7 million in exchange for 35,729 general partner units. The contribution was received in January 2011.

As a result of these transactions, at December 31, 2010, our ownership structure comprised a 0.1% general partnership interest held by QRE GP, 55.1% in limited partner interest held by the Fund and 44.8% in limited partner interests held by public unitholders.

On January 3, 2011, the underwriters exercised their over-allotment option in full to purchase 2,250,000 common units issued by the Partnership at $20.00 per unit. Total net proceeds from the sale of these common units, after deducting the underwriters’ discount and structuring fee, were approximately $42.0 million which, in accordance with the Contribution Agreement were distributed to the Fund as consideration for assets contributed on the Closing Date and reimbursements for pre-formation capital expenditures.

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At September 30, 2011, our ownership structure comprised a 0.1% general partner interest held by QRE GP, a 51.6% in limited partner interest held by the Fund and a 48.3% limited partner interest held by 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 (“GAAP”) for complete annual financial statements. The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. During interim periods, we follow the accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010 (the “Annual Report”), filed with the United States Securities and Exchange Commission (the “SEC”). Please refer to the footnotes to the financial statements in the Annual Report when reviewing the interim financial results. The unaudited consolidated financial statements for the three and nine months ended September 30, 2011 and 2010 include all adjustments (consisting of normal recurring adjustments) we believe are necessary for a fair statement of the results for the interim periods. Operating results for the three and nine month periods ended September 30, 2011 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2011. 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 Annual Report.

Accounting Policy Updates/Revisions

The accounting policies followed by the Partnership and the Predecessor are set forth in Note 2 of the Notes to Consolidated Financial Statements in our Annual Report. There have been no significant changes to these policies during the nine months ended September 30, 2011.

Recent Accounting Pronouncements

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

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

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

NOTE 3 – FAIR VALUE MEASURMENTS

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

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

Level 1 –

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

Level 2 –

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

Level 3 –

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

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

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 forward interest rates and volatility curves. The curves are obtained from independent pricing services.

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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, 2011 and December 31, 2010.

As of September 30, 2011	Total			Level 1		Level 2			Level 3
Assets from commodity derivative contracts	$	61,298		$	-	$	61,298		$	-
Assets from interest rate derivative contracts		146			-		146			-
	$	61,444		$	-	$	61,444		$	-

Liabilities from commodity derivative contracts	$	(499	)	$	-	$	(499	)	$	-
Liabilities from interest rate derivative contracts		(17,288	)		-		(17,288	)		-
	$	(17,787	)	$	-	$	(17,787	)	$	-

As of December 31, 2010	Total			Level 1		Level 2			Level 3
Assets from commodity derivative contracts	$	18,047		$	-	$	18,047		$	-
Liabilities from commodity derivative contracts	$	(26,877	)	$	-	$	(26,877	)	$	-

There have been no transfers between levels within the fair value measurement hierarchy during the three or nine months ended September 30, 2011.

On February 28, 2011, the Predecessor novated certain interest rate derivative instruments to us. These derivative instruments were accounted for at fair value of a $2.9 million net asset position (See Note 4). These derivative instruments are classified as Level 2 fair value measurements.

In June 2011, we entered into modifications of all our existing oil fixed price swap derivative contracts, effectively settling those liability positions as of June 22, 2011. These modifications were accounted for at fair value of $40.7 million (See Note 4). These modifications are classified as Level 2 fair value measurements.

On July 1, 2011, the Predecessor novated certain basis swap derivative instruments to us. These derivative instruments were accounted for at fair value of a $0.3 million liability position (See Note 4). These derivative instruments are classified as Level 2 fair value measurements.

On September 30, 2011, the Predecessor novated certain interest rate derivative instruments to us. These derivative instruments were accounted for at fair value of a $8.5 million liability position (See Note 4). These derivative instruments are classified as Level 2 fair value measurements. This novation was done in anticipation of our acquisition of oil and gas properties from the Fund effective October 1, 2011 (See Note 6 and Note 15).

NOTE 4 – DERIVATIVE ACTIVITIES

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 both the market price of oil, natural gas and natural gas liquids. We use derivatives to reduce our risk of changes in the prices of oil and natural gas. Our policies do not permit the use of derivatives for speculative purposes. 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. Each of the counterparties to our derivative contracts is a lender under our credit facility. We do not post collateral under any of these contracts as they are secured under our credit facility.

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

On May 9, 2011 we entered into a 500 MMBtu/d natural gas collar transaction contract for the 2014 calendar year with a floor of $5.00 per MMBtu and a ceiling of $6.19 MMBtu. On the same day we entered into a 3,000 MMBtu/d natural gas collar transaction contract for the 2015 calendar year with a floor of $5.00 per MMBtu and a ceiling of $7.50 per MMBtu.

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

On July 1, 2011, the Predecessor novated to the Partnership basis swaps with contract dates through 2014. The average hedged differential of the basis swaps range from ($0.15) to ($0.16) during the life of the contract. The fair value of these derivative instruments was $0.3 million of liability positions.

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

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

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

As of September 30, 2011, we had interest rate derivative contracts covering $373.5 million in principal with a fair value of $17.1 million liability. The outstanding balance of our credit facility as of September 30, 2011 was $266.0 million. The additional interest rate derivatives are due to the contracts novated to us by the Predecessor on September 30, 2011 in anticipation of our purchase of oil and gas properties from the Predecessor on October 3, 2011 (see Note 15).

These contracts effectively fix the LIBOR component of our outstanding balance of our credit facility at 2.0% through December 2015. As of September 30, 2011, when the interest rate derivative instruments are considered, we had an effective fixed interest rate of 4.5% comprising a 2.5% applicable margin and 2.0% fixed LIBOR rate. Effective October 1, 2011, the Fund novated additional fixed-for-floating interest rate swaps to us covering $98.4 million of weighted-average borrowings under our revolving credit facility from October 1, 2011 to December 31, 2015. After these additional interest rate derivatives are considered, we have an effective fixed interest rate of 4.6% comprising a 2.5% applicable margin and 2.1% fixed LIBOR rate.

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As of September 30, 2011, the notional volumes of our commodity derivative contracts were:

Commodity	Index	October 1 - December 31, 2011			2012			2013			2014			2015
Oil position:
Fixed price swaps
Hedged volume (Bbls/d)	WTI		2,238			2,039			2,076			2,090			2,000
Average price ($/Bbl)		$	96.40		$	98.50		$	98.50		$	97.75		$	97.10

Natural gas position:
Fixed price swaps
Hedged volume (MMBtu/d)	NYMEX		9,045			8,192			7,474			7,544			3,398
Average price ($/MMBtu)		$	7.38		$	6.45		$	6.45		$	6.30		$	5.52

Basis swaps
Hedged volume (MMBtu/d)	NYMEX		7,335			6,723			5,966			5,766			4,300
Hedged differential ($/MMBtu)		$	(0.13	)	$	(0.16	)	$	(0.17	)	$	(0.17	)	$	(0.17	)

Collars
Hedged volume (MMBtu/d)	NYMEX		-			-			-			500			3,000
Average floor price ($/MMBtu)		$	-		$	-		$	-		$	5.00		$	5.00
Average ceiling price ($/MMBtu)		$	-		$	-		$	-		$	6.19		$	7.50

As of December 31, 2010, the notional volumes of our derivative contracts were:

Commodity	Index	2011		2012		2013		2014		2015
Oil position:
Fixed price swaps
Hedged volume (Bbls/d)	WTI		2,238		2,039		2,076		2,090		2,000
Average price ($/Bbl)		$	85.00	$	85.25	$	85.35	$	84.58	$	87.40

Natural gas position:
Fixed price swaps
Hedged volume (MMBtu/d)	NYMEX		9,178		8,192		7,474		7,544		3,398
Average price ($/MMBtu)		$	7.26	$	6.45	$	6.45	$	6.30	$	5.52

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We have elected not to designate any of our derivatives as hedging instruments. As a result, these derivative instruments are marked to fair value 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. The fair value of these derivatives was as follows as of the dates indicated:

	September 30, 2011				December 31, 2010
	Asset Derivative Contracts		Liability Derivative Contracts		Asset Derivative Contracts		Liability Derivative Contracts
Commodity contracts	$	61,298	$	499	$	18,047	$	26,877
Interest rate contracts		146		17,288		-		-
	$	61,444	$	17,787	$	18,047	$	26,877

Commodity
Current	$	21,305	$	151	$	9,027	$	7,045
Noncurrent		39,993		348		9,020		19,832
	$	61,298	$	499	$	18,047	$	26,877
Interest
Current	$	-	$	6,261	$	-	$	-
Noncurrent		146	$	11,027		-		-
	$	146	$	17,288	$	-	$	-

Total derivatives
Current	$	21,305	$	6,412	$	9,027	$	7,045
Noncurrent		40,139		11,375		9,020		19,832
	$	61,444	$	17,787	$	18,047	$	26,877

The following table presents the impact of derivatives and their location within our unaudited consolidated statements of operations for the three and nine months period ended September 30, 2011 and September 30, 2010:

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
	Partnership			Predecessor			Partnership			Predecessor
Realized gains (losses):
Commodity contracts (1)	$	3,581		$	2,219		$	(37,271	)	$	5,132
Interest rate swaps		(969	)		(2,278	)		(2,231	)		(2,807	)
Total	$	2,612		$	(59	)	$	(39,502	)	$	2,325

Unrealized gains (losses):
Commodity contracts (1)	$	53,172		$	(3,501	)	$	69,904		$	41,432
Interest rate swaps		(6,891	)		(10,960	)		(11,541	)		(18,194	)
Total	$	46,281		$	(14,461	)	$	58,363		$	23,238

Total gains (losses):
Commodity contracts	$	56,753		$	(1,282	)	$	32,633		$	46,564
Interest rate swaps (2)		(7,860	)		(13,238	)		(13,772	)		(21,001	)
Total	$	48,893		$	(14,520	)	$	18,861		$	25,563

(1)

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

(2)

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

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NOTE 5 – INCOME TAXES

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

We are subject to Texas margin tax. We recorded a deferred tax liability of less than $0.1 million related to our operations located in Texas as of September 30, 2011. We recorded a deferred tax asset of $0.3 million related to our operations located in Texas as of December 31, 2010. The deferred tax asset is included in noncurrent assets and the deferred tax liability is included in noncurrent liabilities on the consolidated balance sheet. We recognized income tax expense of $0.3 million and $0.4 million for the three and nine months ended September 30, 2011.

NOTE 6 – OTHER ASSETS

As of September 30, 2011 and December 31, 2010, the Partnership had the following other assets:

	September 30, 2011		December 31, 2010
Deferred financing costs, net	$	2,429	$	2,645
Deferred reduction to net asset contribution		8,476		-
Other assets	$	10,905	$	2,645

On September 30, 2011, the Partnership recorded an $8.5 million adjustment to other assets related to the novation of interest rate derivatives from the Predecessor (see Note 4). These novated interest rates derivatives are part of the purchase of oil and gas properties on October 3, 2011 (see Note 15). The other asset is a deferred reduction to the net asset contribution effective October 1, 2011 and will be recorded as part of the closing to partners’ capital.

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

Changes in our asset retirement obligations for the periods indicated are presented in the following table:

Liability for asset retirement obligation as of December 31, 2010	$	18,288
Accretion expense		865
Liabilities settled		(163	)
Liability for asset retirement obligation as of September 30, 2011	$	18,990

Current portion of asset retirement obligations	$	1,686
Non-current portion of asset retirement obligations		17,304
Liability for asset retirement obligation as of September 30, 2011	$	18,990

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NOTE 8 – LONG-TERM DEBT

Senior Secured Revolving Credit Facility

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

The Credit Agreement provides for a five-year, $750.0 million revolving credit facility maturing on December 22, 2015, with a borrowing base of $330.0 million as of September 30, 2011. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 each year based on an engineering report with respect to our estimated oil, natural gas and NGL reserves, which will take into account the prevailing oil, natural gas and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. On July 13, 2011, we received an interim borrowing base redetermination under our Credit Agreement which increased the borrowing base to $330.0 million. We requested and received this interim redetermination as a result of improvements in our net derivative position due to the buyup of our existing oil fixed price swap contracts in June 2011. 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 our wholly owned subsidiary, OLLC, and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum.

As of September 30, 2011 and December 31, 2010, we had $266.0 million and $225.0 million of borrowings outstanding and $64.0 million of borrowing availability as of September 30, 2011. For the nine months ended September 30, 2011, the weighted average interest rate on the revolver was 4.2%.

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 (including a prohibition on our ability to pay distributions to our unitholders if our borrowing base usage exceeds 95%); 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 reviewed quarterly financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production from total proved reserves for the next two years and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in our 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.

On October 3, 2011, we amended our revolving credit facility to, among other things, increase the borrowing base by $300.0 million, resulting in a total borrowing base of $630 million. This amendment also modified certain provisions and covenants of to allow for the successful consummation of the transactions related to the Purchase Agreement, the issuance of the Preferred Units and the related entry into the amendment to our partnership agreement (See Note 15). This amendment removes the restriction on our ability to pay distributions to our unitholders based on borrowing base utilization. The administrative agent of our Credit Agreement has accepted this amendment in lieu of our semiannual redetermination required on November 1, 2011.

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NOTE 9 — PARTNERS’ CAPITAL

Units Outstanding

As of September 30, 2011, our outstanding partnership interests consisted of 28,565,344 outstanding common units and 7,145,866 outstanding subordinated units, representing a 99.9% limited partnership interest in us, and a 0.1% general partnership interest represented by 35,729 general partner units.

Allocations of Net Income (Loss)

Net income (loss) is allocated between QRE GP and the limited partner 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. The Credit Agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the Credit Agreement, occurs or would result from the cash distribution.

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

Distributions for the nine months ended September 30, 2011 were as follows:

				Limited Partners
	For the	General		Public		Affiliated						Distributions
Date Paid	period ended	Partner		Common		Common		Subordinated		Total		per unit
(In thousands, except per unit amounts)
February 11, 2011	December 31, 2010	$	2	$	779	$	506	$	320	$	1,607	$	0.0448
May 13, 2011	March 31, 2011		15		7,186		4,660		2,948		14,809		0.4125
August 12, 2011	June 30, 2011		15		7,184		4,660		2,948		14,807		0.4125

NOTE 10 – COMMITMENTS AND CONTINGENCIES

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our financial position, results of operations or cash flows.

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NOTE 11 – NET INCOME PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income per limited partner unit for the following periods:

	(In thousands except per share amounts)
	Three months ended September 30, 2011		Nine months ended September 30, 2011

Net income	$	51,930	$	38,513
Less: General partner's 0.1% interest in net income		52		39
Limited partners' interest in net income	$	51,878	$	38,474
Common unitholders' interest in net income	$	41,540	$	30,829
Subordinated unitholders' interest in net income	$	10,338	$	7,645
Net income per limited partner unit:
Common units (basic and diluted)	$	1.45	$	1.07
Subordinated units (basic and diluted)	$	1.45	$	1.07
Weighted average limited partner units outstanding:
Common units (basic and diluted) (1)		28,713		28,698
Subordinated units (basic and diluted)		7,146		7,146

(1) Includes 148,345 and 155,407 weighted-average units of outstanding unvested unit-based awards for the three and nine months ended September 30, 2011 (See Note 12)

Net income per limited partner unit is determined by dividing the net income available to the limited partner unitholders, after deducting QRE GP’s 0.1% interest in net income, by the weighted average number of limited partner units outstanding during the three and nine months ended September 30, 2011. We had 28,565,344 common units and 7,145,866 subordinated units outstanding as of September 30, 2011.

NOTE 12 – UNIT-BASED COMPENSATION

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

During the three and nine months ended September 30, 2011, we recognized compensation expense of $0.4 million and $1.0 million related to equity awards. As of September 30, 2011 we had 140,170 unit awards outstanding with unrecognized compensation expense related to nonvested restricted unit awards of $2.3 million which we expect to recognize in expense over a weighted average remaining vesting period of approximately 2 years.

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

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

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

The following table summarizes our unit-based awards for the nine months ended September 30, 2011 (units in thousands):

	Nine months ended September 30, 2011
	Number of Unvested Units			Weighted Average Grant-Date Fair Value per unit
Unvested units at beginning of period		148		$	20.03
Granted (1)		44		$	21.42
Forfeited		(30	)	$	20.66
Vested (1) (2)		(22	)	$	20.14
Unvested units at end of period		140		$	20.32

(1) Includes 9,317 units granted to our independent directors for services performed for us.

(2) Includes 12,750 other units vested during the period.

For the three months ended September 30, 2011, we had approximately 148,345 weighted average restricted units outstanding.

NOTE 13 – RELATED PARTY TRANSACTIONS

In connection with the closing of the IPO, we entered into agreements with QRE GP and its affiliates. The following is a description of those agreements.

Services Agreement

On December 22, 2010, in connection with the closing of the IPO, we entered into a service agreement (the “Services Agreement”) with QRM, QRE GP and OLLC, pursuant to which QRM agreed to provide the administrative and acquisition advisory services necessary to allow QRE GP to manage, operate and grow our business. Under the Services Agreement, from the closing of the IPO through December 31, 2012, QRM is entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. After December 31, 2012, in lieu of the quarterly administrative services fee, QRE GP will reimburse QRM, on a quarterly basis, for the allocable expenses QRM incurs in its performance under the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM.

For the nine months ended September 30, 2011 the Fund charged us $0.8 million in administrative service fees in accordance with the Services Agreement. For the three months ended September 30, 2011, we recognized $0.7 million in administrative service fees primarily as a result of an increase in adjusted EBITDA due to the realized gain on oil and gas derivatives during the quarter. The administrative service fee is recorded in general and administrative and other in the consolidated statement of operations. The settlement of the administrative service fee for each quarter is made in the subsequent quarter.

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In connection with the management of our business, QRM provides services for invoicing and collection of our revenues as well as processing of payments to our vendors. Periodically QRM remits cash to us for the net working capital received on our behalf. Changes in the affiliate (payable)/receivable balances during the nine months ended September 30, 2011 are included below:

Balance at December 31, 2010	$	(442	)
Revenues and other increases (1)		83,841
Expenditures and other		(42,718	)
Settlements from the Fund		(34,202	)
Balance at September 30, 2011	$	6,479

(1)

Includes $0.7 million in overhead producing credits and $1.3 million of proceeds from the sale of oil and gas leases received by the Fund on our behalf.

Other Contributions to Partners’ Capital

Other contributions to partners’ capital for the nine months ended September 30, 2011 include the following items:

Noncash general and administrative expense contributed by the Fund (1)	$	9,544
Fair value of interest rate derivatives novated to us from the Fund (2)		2,600
Prepaid insurance incurred by the Fund on our behalf (3)		224
Total other contributions from the Fund	$	12,368

(1)

Represents our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us.

(2)

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

(3)

QRM also incurred repaid insurance on our behalf, but not reimbursable by us.

Other Related Party Activity

On September 30, 2011, the Predecessor novated to us fixed-for-floating interest rate swaps covering and additional $120.0 million in weighted-average borrowings under our credit facility from October 1, 2011 to December 31, 2015. The fair value of these derivative instruments was an $8.5 million liability position. As a result of this novation, we recorded an $8.5 million adjustment to other assets as these novated interest rates derivatives are part of the purchase of oil and gas properties on October 3, 2011 (see Note 15). The other asset is a deferred reduction to the net asset contribution effective October 1, 2011 and will be recorded as part of the closing to partners’ capital.

Omnibus Agreement

We entered into an omnibus agreement (the “Omnibus Agreement”) by and among QRE GP, OLLC, the Fund and QA Global GP, LLC. The Omnibus Agreement provides for, among other items, the following:

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

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

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

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 is 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,

the value of our commodity derivative contracts valued at SEC strip prices and discounted at 10% per annum, 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 three and nine months ended September 30, 2011, no management incentive fees were earned by or paid to QRE GP.

Long–Term Incentive Plan

On December 22, 2010, in connection with the closing of the IPO, the Board of Directors of QRE GP adopted the Plan to compensate employees, officers, consultants and directors and consultants of QRE GP and those of its affiliates, including QRM, who perform services for us. As of September 30, 2011, 140,170 restricted unit awards with a grant date fair value totaling $2.8 million were outstanding under the Plan. For additional discussion regarding the Plan see Note 12.

Distributions of available cash to QRE GP and affiliates

We will generally make cash distributions to our unitholders and QRE GP pro rata, including QRE GP and our affiliates. As of September 30, 2011, QRE GP and its affiliates held 11,297,737 common units, all of the subordinated units and 35,729 general partner units. We distributed less than $0.1 million to QRE GP during the nine months ended September 30, 2011.

Our Relationship with Bank of America

Don Powell, one of our independent directors, is also a director of Bank of America Corporation (“BOA”). An affiliate of BOA is a lender under our credit facility.

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NOTE 14 – SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information for the nine months ended September 30, 2011 and 2010 is provided below:

	Partnership			Predecessor
	Nine Months Ended September 30, 2011			Nine Months Ended September 30, 2010
Supplemental Cash Flow Information
Cash paid for interest	$	7,639		$	8,666
Cash paid for income taxes	$	-		$	-
Non-cash Investing And Financing Activities
Interest rate swaps novated from the Fund	$	(5,876	)	$	-
Change in accrued capital expenditures	$	1,565		$	7,379
Insurance premium financed	$	-		$	118
Additions to asset retirement obligations	$	-		$	26,563

NOTE 15 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after September 30, 2011, through the issuance of the financial statements.

On October 3, 2011 (effective October 1, 2011) we completed an acquisition of certain oil and gas properties located in the Permian Basin, Ark-La-Tex and Mid-Continent areas from the Fund for an aggregate purchase price of $577.0 million, pursuant to a Purchase and Sale Agreement (the “Purchase Agreement”) dated September 12, 2011. Our acquisition of these properties will be accounted for as a transfer of net assets between entities under common control.

In exchange for the assets, we assumed $227.0 million in debt from the Fund which was repaid at closing and issued to the Fund 16,666,667 unregistered Class C Convertible Preferred Units (“Preferred Units”). The Preferred Units will receive a preferred quarterly distribution of $0.21 per unit equal to 4.0% annual coupon on the par value of $21.00 for the first three years following the date of issuance. After three years, the quarterly cash distribution will be equal to the greater of (a) $0.475 per unit or (b) the cash distribution payable on each Common Unit for such quarter. The Preferred Units are convertible, subject to certain limitations, into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment.

In connection with the issuance of the Preferred Units, on October 3, 2011, we amended our First Amended and Restated Agreement of Limited Partnership to designate and create the Preferred Units and set forth the rights, preferences and privileges of such units, including the respective conversion rights held by the holders of the Preferred Units and us.

On October 3, 2011, we amended our revolving credit facility to increase the borrowing base by $300.0 million. We borrowed $234.0 million to repay $227.0 million in assumed debt from the Fund in connection with the Purchase Agreement and pay approximately $7.0 million in estimated transaction fees. The amendment to the revolving credit facility also modified certain provisions and covenants to allow for the successful consummation of the transactions related to the Purchase Agreement, the issuance of Preferred Units and the related entry into the amendment to our partnership agreement. This transaction increased our outstanding borrowings on our credit facility to $500.0 million which matures in December 2015.

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Effective October 1, 2011, the Fund novated additional fixed-for-floating interest rate swaps to us covering $98.4 million of weighted-average borrowings under our revolving credit facility from October 1, 2011 to December 31, 2015. After consideration of this novation and our other fixed-for-floating interest rate swaps, we had the following interest rate derivatives:

Term	Weighted Average Fixed Rate			Weighted Average Amount (in millions)
October 1, 2011 to December 31, 2011		2.15	%	$	475.5
January 1, 2012 to December 31, 2012		2.14	%	$	483.0
January 1, 2013 to December 31, 2013		2.13	%	$	484.0
January 1, 2014 to December 31, 2014		2.12	%	$	484.6
January 1, 2015 to December 31, 2015		2.11	%	$	484.2

The Fund also novated the following oil and gas derivatives to us effective October 1, 2011:

Commodity	Index	October 1 - December 31, 2011			2012			2013			2014			2015			2016
Oil position:
Fixed price swaps
Hedged volume (Bbls/d)	WTI		1,961			1,986			2,067			1,621			940			270
Average price ($/Bbl)		$	98.20		$	98.94		$	97.96		$	97.63		$	97.63		$	97.63

Collars
Hedged volume (Bbls/d)	WTI		-			-			-			425			1,025			-
Average floor price ($/Bbls)		$	-		$	-		$	-		$	90.00		$	90.00		$	-
Average ceiling price ($/Bbls)		$	-		$	-		$	-		$	106.50		$	110.00		$	-

Natural gas position:
Fixed price swaps
Hedged volume (MMBtu/d)	NYMEX		26,097			22,200			22,200			18,362			2,702			-
Average price ($/MMBtu)		$	5.23		$	5.65		$	5.94		$	6.20		$	5.52		$	-

Basis swaps
Hedged volume (MMBtu/d)	NYMEX		15,600			14,000			12,500			11,300			10,100			-
Hedged differential ($/MMBtu)		$	(0.10	)	$	(0.14	)	$	(0.17	)	$	(0.19	)	$	(0.20	)	$	-

Collars
Hedged volume (MMBtu/d)	NYMEX		-			2,623			2,466			4,466			15,000			-
Average floor price ($/MMBtu)		$	-		$	6.50		$	6.50		$	5.83		$	5.00		$	-
Average ceiling price ($/MMBtu)		$	-		$	8.60		$	8.65		$	7.66		$	7.48		$	-

On October 4, 2011, we announced the board of directors of QRE GP approved a cash distribution for the third quarter of 2011 of $0.4125 per unit. On November 11, 2011 we paid $14.8 million to unitholders of record at the close of business on October 31, 2011.

Also on October 4, 2011, we announced the board of directors of QRE GP approved an increase in the cash distribution attributable to the fourth quarter of 2011 to $0.4750 per unit for all outstanding units. The $0.4750 per unit cash distribution will be payable on February 10, 2012 to unitholders of record at the close of business on January 30, 2012.

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

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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 of Financial Condition and Results of Operations in Part II. —Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 (the “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 Annual Report and in Part II. —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 own and exploit producing oil and natural gas properties in North America. Certain of our Predecessor’s subsidiary limited partnerships (collectively known as the “Fund”), comprise Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC. 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”).

On December 22, 2010, in connection with our IPO, the Fund conveyed to us oil and natural gas producing properties located in Alabama, Arkansas, Kansas, Louisiana, New Mexico, Oklahoma, Texas and an 8.05% overriding oil royalty interest in Florida. Our average daily oil and natural gas production for the three months ended September 30, 2011 was 5.1 Mboe/d and for the nine months ended September 30, 2011 was 5.3 Mboe/d.

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 exploration 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. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Our discussion and analysis of the results of operations below includes a comparison of the three months ended September 30, 2011 to the three months ended June 30, 2011. We believe such a comparison will enable the reader to assess material changes in our results of operations during calendar year 2011; however, we expect we will discuss material changes between comparable interim periods beginning with our Quarterly Report on Form 10-Q for the quarter ending March 31, 2011 and will no longer compare intra-year interim periods. Our first interim financial statements in calendar year 2012 will discuss material changes in our results of operations from three months ended March 31, 2012 to the corresponding three months ended March 31, 2011. Interim filings subsequent to the calendar year 2011 filings will not compare intra-year three month periods.

Recent Events

On October 3, 2011 (effective October 1, 2011), we completed an acquisition of certain oil and gas properties (the “Acquisition”) located in the Permian Basin, Ark-La-Tex and Mid-Continent areas from the Fund for an aggregate purchase price of $577.0 million, pursuant to a Purchase and Sale Agreement (the “Purchase Agreement”). Our acquisition of these properties will be accounted for as a transfer of net assets between entities under common control.

In exchange for the assets, we assumed $227.0 million in debt from the Fund which was repaid at closing and issued to the Fund 16,666,667 unregistered Class C Convertible Preferred Units (“Preferred Units”). The Preferred Units will receive a preferred quarterly distribution of $0.21 per unit, equal to 4.0% annual coupon on the par value of $21.00, for the first three years following the date of issuance. After three years, the quarterly cash distribution will be equal to the greater of (a) $0.4750 per unit or (b) the cash distribution payable on each Common Unit for such quarter. The Preferred Units are convertible into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment.

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Also on October 3, 2011, we amended our revolving credit facility to increase the borrowing base by $300.0 million and our borrowings by $234.0 million. We use such borrowings to repay $227.0 million in assumed debt from the Fund in connection with the Purchase Agreement and pay $7.0 million in estimated transaction fees. The amendment to the revolving credit facility also modified certain provisions and covenants of to allow for the successful consummation of the transactions related to the Purchase Agreement, the issuance of the Preferred Units and the related entry into the amendment to our partnership agreement.

For 2011, we have estimated our maintenance capital expenditures to be approximately $12.5 million on our asset base as of September 30, 2011. Following the Acquisition, our estimated maintenance capital expenditures are approximately $12.5 million for the fourth quarter of 2011.

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Results of Operations

The table below summarizes certain of the results of operations attributable to the Partnership and the Predecessor for the periods indicated. Because the historical results of the Predecessor include results for both the properties conveyed to us in connection with our IPO and properties retained by the Predecessor, we do not consider these historical results of the Predecessor for operations and period-to-period comparisons of our results as indicative of our future results. Nevertheless, they are presented here to provide a possible context for our current operations. These results are presented for illustrative purposes only and are not indicative of future results of the Partnership. The prior year Predecessor data reflects only those properties that were owned by the Predecessor at that point.

	Partnership									Predecessor
	Three Months Ended June 30, 2011			Three Months Ended September 30, 2011			Nine Months Ended September 30, 2011			Three Months Ended September 30, 2010			Nine Months Ended September 30, 2010
Revenues:
Oil sales	$	23,726		$	20,646		$	67,889		$	51,895		$	112,972
Natural gas sales		5,483			5,317			16,062			25,503			45,800
Natural gas liquids sales		2,170			2,528			6,488			4,261			9,744
Processing and other		274			217			689			2,819			6,954
Total Revenue		31,653			28,708			91,128			84,478			175,470
Operating Expenses:
Lease operating expenses		6,627			7,932			20,177			21,828			45,638
Workover expenses		(94	)		698			1,260			1,725			6,514
Production and other taxes		2,155			1,990			6,123			6,430			12,528
Processing and transportation		89			307			918			1,316			3,876
Total production expenses		8,777			10,927			28,478			31,299			68,556
Depreciation, depletion and amortization		8,636			7,832			25,043			25,908			45,149
Accretion of asset retirement obligations		290			308			865			1,193			2,648
Management fees		-			-			-			2,915			7,885
Acquisition evaluation costs		-			-			-			155			1,197
General and administrative and other		3,344			4,092			10,869			8,547			19,177
Bargain purchase gain		-			-			-			1,020			-
Total operating expenses		21,047			23,159			65,255			71,037			144,612
Operating income		10,606			5,549			25,873			13,441			30,858
Other income (expense):
Equity in earnings of Ute Energy, LLC		-			-			-			782			1,490
Realized (losses) gains on commodity derivative instruments		(42,161	)		3,581			(37,271	)		2,219			5,132
Unrealized gains (losses) on commodity derivative instruments		55,575			53,172			69,904			(3,501	)		41,432
Gain on equity share issuance		-			-			-			4,064			4,064
Interest expense		(7,854	)		(10,097	)		(19,627	)		(18,481	)		(31,365	)
Other income (expense)		-			-			-			2			(407	)
Total other income (expense), net		5,560			46,656			13,006			(14,915	)		20,346
Income (loss) before income taxes		16,166			52,205			38,879			(1,474	)		51,204
Income tax expense, net		(235	)		(275	)		(366	)		(12	)		(223	)
Net income (loss)	$	15,931		$	51,930		$	38,513		$	(1,486	)	$	50,981
Production data:
Oil (MBbls)		254			234			734			726			1,573
Natural gas (MMcf)		1,167			1,166			3,586			5,616			10,122
Natural gas liquids (MBbls)		40			45			123			109			228
Total (MBoe)		489			473			1,455			1,771			3,488
Average net production (Boe/d)		5,368			5,145			5,328			19,462			19,271
Average sales price per unit:
Oil (per Bbl)	$	93.41		$	88.23		$	92.49		$	71.48		$	71.82
Natural gas (per Mcf)	$	4.70		$	4.56		$	4.48		$	4.54		$	4.52
Natural gas liquids (per Bbl)	$	54.25		$	56.18		$	52.75		$	39.09		$	42.74
Average unit cost per Boe:
Lease operating expense	$	13.57		$	16.76		$	13.87		$	12.33		$	13.08
Workover expense	$	(0.19	)	$	1.47		$	0.87		$	0.97		$	1.87
Production and other taxes	$	4.41		$	4.20		$	4.21		$	3.63		$	3.59
Management fees	$	-		$	-		$	-		$	1.65		$	2.26
Depreciation, depletion and amortization	$	17.68		$	16.55		$	17.22		$	14.63		$	12.94
General and administrative expenses	$	6.85		$	8.65		$	7.47		$	4.83		$	5.50

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Factors Affecting the Comparability of the Historical Financial Results of Us and Our Predecessor

The comparability of our results for the three and nine months ended September 30, 2011 and the Predecessor’s results for the three and nine months ended September 30, 2010 is impacted as follows:

Our results for the three and nine months ended September 30, 2011 include additional operating results from certain properties that were contributed to us in connection with the Predecessor’s Denbury acquisition, which occurred in May 2010; and therefore not part of our Predecessor’s operating results for the entire three and nine months ended September 30, 2010.

Our results for the three and nine months ended September 30, 2011 do not include the operating results of certain properties owned by the Predecessor during the three and nine month periods ended September 30, 2010 that were not contributed to us.

Accordingly, we have presented our comparison of our results for the three months ended September 30, 2011 against our results for the three months ended June 30, 2011 below.

Partnership’s Results of Operations

Results for the Three Months Ended September 30, 2011 Compared to the Three Months Ended June 30, 2011

We recorded net income of $51.9 million for the three months ended September 30, 2011 compared to net income of $15.9 million for the three months ended June 30, 2011. The following discussion summarizes key items of comparison and their related change.

Sales Revenues. Sales revenues decreased $3.0 million to $28.7 million for the three months ended September 30, 2011 compared to $31.7 million for the three months ended June 30, 2011. The decrease is due to a reduction in oil sales of $3.1 million to $20.6 million for the three months ended September 30, 2011 from $23.7 million for the three months ended June 30, 2011. Lower oil sales volumes reduced revenues by $1.8 million as a result of a decrease of 20 MBbls, or 217 Boe/d, to 234 MBbls for the three months ended September 30, 2011 from 254 MBbls for the three months ended June 30, 2011 as a result of a decrease in prior period accrual estimates, power outages in West Texas and unscheduled downtime on Gulf Coast nonoperated properties. Lower average sale prices for oil also reduced revenues by $1.3 million due to a decrease of $5.18 per Bbl to $88.23 for the three months ended September 30, 2011 from $93.41 per Bbl for the three months ended June 30, 2011. These decreases in oil sales were partially offset by a net increase of $0.1 million in other product revenues.

Effects of Commodity Derivative Contracts. Our impact from realized gains (losses) on commodity derivative instruments increased our net income by $45.8 million to a $3.6 million realized gain during the three months ended September 30, 2011 compared to a $42.2 million realized loss during the three months ended June 30, 2011. Our impact from unrealized gains on commodity derivative instruments decreased our net income by $2.4 million to a $53.2 million unrealized gain during the three months ended September 30, 2011 compared to a $55.6 million unrealized gain during the three months ended June 30, 2011. The realized losses and unrealized gains during the three months ended June 30, 2011 are primarily due to the modifications of our derivative contracts described in the paragraph below.

On June 22, 2011 we entered into modifications of all our existing oil fixed priced swap derivative contracts with cash payments to counterparties recognized as a realized loss of $40.7 million. Concurrent with this cash payment, we also recognized an offsetting unrealized gain of $40.7 million due to the modification of the fixed prices up to market price on the trade date. The modification increased the weighted average prices on our fixed price oil swap contracts by 14% from $85.55 per Bbl to $97.78 per Bbl for the second half of 2011 through 2015.

Our realized gains on commodity derivatives exclusive of the modifications above increased net income by $5.1 million as we recognized a $3.6 million realized gain for the three months ended September 30, 2011 compared to a $1.5 million loss for the three months ended June 30, 2011. The increase in gains quarter over quarter is primarily due to receipts from counter parties to settle oil contracts.

Our unrealized gains on commodity derivatives exclusive of the modifications above increased net income by $38.3 million as we recognized a $53.2 million unrealized gain for the three months ended September 30, 2011 compared to a $14.9 million unrealized gain for the three months ended June 30, 2011. The increase in unrealized gains quarter over quarter is primarily due to reductions in forward price curves on oil contracts.

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Production Expenses. Our production expense increased $2.1 million to $10.9 million for the three months ended September 30, 2011 compared to $8.8 million for the three months ended June 30, 2011.

The increase in our lease operating expense of $1.3 million was due to an increase in prior period accrual estimates and well servicing on Permian Basin area properties during the three months ended September 30, 2011.

Also contributing to the increase in production expenses was an increase of $0.8 million in prior period accrual estimates of workovers and additional workover expenses on Arklatex area operated properties during the three months ended September 30, 2011.

The $0.2 million decrease in production and other taxes is proportional to the decrease in revenues quarter over quarter.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization expense decreased $0.8 million to $7.8 million for the three months ended September 30, 2011 compared to $8.6 million for the three months ended June 30, 2011. The decrease was primarily due to a reduction in the depreciation, depletion and amortization rate used on production and reserves due to increases in the Partnership’s reserves as of September 30, 2011 compared to June 30, 2011, which contributed a $0.5 million decrease in expense. Changes in production volume contributed an additional $0.3 million decrease in expense quarter over quarter. On a per unit basis, depreciation, depletion and amortization expense decreased by $1.13 to $16.55 per Boe in the third quarter versus $17.68 per Boe in the second quarter primarily due to lower oil production for the three months ended September 30, 2011.

General and Administrative and Other Expenses. Our general and administrative and other expenses increased $0.7 million to $4.1 million, during the three months ended September 30, 2011 compared to $3.3 million, during the three months ended June 30, 2011. The increase in general and administrative expenses is primarily due to additional consulting and professional fees due to the accounting and reporting requirements related to the acquisition from our Predecessor.

Interest Expense, net. Net interest expense was $10.1 million for the three months ended September 30, 2011 for an increase of $2.2 million from $7.9 million for the three months ended June 30, 2011. The increase in interest expense was primarily due to losses on interest rate derivatives of $1.8 million.

Results for the Nine Months Ended September 30, 2011.

We recorded net income of $38.5 million for the nine months ended September 30, 2011.

Sales Revenues. Sales revenues of $91.1 million for the nine months ended September 30, 2011 consisted of oil sales of $67.9 million, natural gas sales of $16.0 million and NGL sales of $6.5 million. Oil sales volumes were 734 MBbls and the average sales price was $92.49 per Bbl. Natural gas sales volumes were 3,586 MMcf and the average sales price was $4.48 per Mcf. NGL sales volumes were 123 MBbls and the average sales price was $52.75 per Bbl. Production for the nine months ended September 30, 2011 was 5.4 MBoe/d. In addition, processing and other revenues were $0.7 million generated primarily from sulfur revenue.

Effects of Commodity Derivative Contracts. Realized losses on commodity derivatives for the nine months ended September 30, 2011 were $37.3 million. Unrealized gains on commodity derivatives for the nine months ended September 30, 2011 were $69.9 million.

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Our realized gains on commodity derivatives exclusive of the modifications above were $3.4 million for the nine months ended September 30, 2011 due to natural gas settlements, partially offset by oil settlements.

Our unrealized gains on commodity derivatives exclusive of the modifications above were $29.2 million for the nine months ended September 30, 2011 primarily due to unrealized gains on oil contracts partially offset by unrealized losses on natural gas contracts.

Production Expenses. During the nine months ended September 30, 2011, our production expenses were $28.5 million, primarily comprising $20.2 million in lease operating expenses, $1.3 million in workover expenses and $6.1 million in production and other taxes.

Depreciation, Depletion and Amortization Expenses. For the nine months ended September 30, 2011, our depreciation, depletion and amortization expenses were $25.0 million, or $17.22 per Boe.

General and Administrative and Other Expenses. For the nine months ended September 30, 2011, our general and administrative and other expenses were $10.9 million.

Interest Expense, net. Net interest expense was $19.6 million for the nine months ended September 30, 2011 comprising $5.8 million in interest for the revolver balance and $13.8 million related to interest rate derivatives.

Predecessor Results of Operations – for Three Months Ended September 30, 2010

Sales Revenues. Sales revenues were $84.5 million for the three months ended September 30, 2010, consisting of oil sales of $51.9 million, natural gas sales of $25.5 million and NGL sales of $4.3 million. Oil sales volumes were 726 MBbls and the average sales price was $71.48 per Bbl. Natural gas volumes were 5,616 MMcf and the average sale price was $4.54 per Mcf. NGL volumes were 109 MBbls and the average sales price was $39.09 per Bbl. Production for the three months ended September 30, 2010 was 19.5 MBoe/d. In addition, processing and other revenues were $2.8 million generated primarily from sulfur revenue.

Effects of Commodity Derivative Contracts. Due to decreases in oil and natural gas prices, our Predecessor recorded a net loss from our commodity derivatives program during the period of $1.3 million, composed of a realized gain of $2.2 million and an unrealized loss of $3.5 million.

Production Expenses. Our Predecessor’s production expenses were $31.3 million, primarily comprising $21.8 million in lease operating expenses $1.7 million in workover expenses and $6.4 million in production and other taxes.

Depreciation, Depletion and Amortization Expenses. Our Predecessor’s depreciation, depletion and amortization expenses were $25.9 million, or $14.63 per Boe produced, during the period.

Management Fee. Our Predecessor’s management fees were $2.9 million for the three months ended September 30, 2010.

General and Administrative and Other Expenses. Our Predecessor’s general and administrative and other expenses were $8.5 million, or for the three months ended September 30, 2010.

Interest Expense, net. Interest expense was $18.5 million for the three months ended September 30, 2010 which included deferred financing cost amortization of $0.7 million.

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Predecessor Results of Operations – for the Nine Months Ended September 30, 2010

Sales Revenues. Sales revenues were $175.5 million for the nine months ended September 30, 2010 comprising oil sales of $113.0 million, natural gas sales of $45.8 million and NGL sales of $9.7 million. Oil sales volumes were 1,573 MBbls and the average sales price was $71.82 per Bbl. Natural gas volumes were 10,122 MMcf and the average sale price was $4.52 per Mcf. NGL volumes were 228 MBbls and the average sales price was $42.74 per Bbl. Production for the nine months ended September 30, 2010 was 19.3 MBoe/d. In addition, processing and other revenues were $7.0 million generated primarily from sulfur revenue.

Effects of Commodity Derivative Contracts. Due to increases in oil and natural gas prices, our Predecessor recorded a net gain from our commodity derivatives program during the period of $46.5 million, composed of a realized gain of $5.1 million and an unrealized gain of $41.4 million.

Production Expenses. Our Predecessor’s production expenses were $68.6 million, primarily comprising $45.6 million in lease operating expenses, $6.5 million in workover expenses and $12.5 million in production and other taxes.

Depreciation, Depletion and Amortization Expenses. Our Predecessor’s depreciation, depletion and amortization expenses were $45.1 million, produced, during the period.

Management Fee. Our Predecessor’s management fees were $7.9 million for the nine months ended September 30, 2010.

General and Administrative and Other Expenses. Our Predecessor’s general and administrative and other expenses were $19.2 million, for the nine months ended September 30, 2010.

Interest Expense, net. Interest expense was $31.4 million for the nine months ended September 30, 2010 which included deferred financing cost amortization of $2.0 million.

Liquidity and Capital Resources

Our cash flow used in operating activities for the nine months ended September 30, 2011, was $3.5 million, which included a payment of $40.7 million to increase the fixed price we will receive in future periods under all our existing oil fixed-price swap derivative contracts effectively settling a portion of those liabilities as of June 22, 2011. Funding for the payment to modify these contracts was obtained from borrowings under our credit facility and not operating cash flows.

Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our credit facility. 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, 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.

As of September 30, 2011, our liquidity of $65.2 million consisted of $1.2 million of available cash and $64.0 million of availability under our credit facility. 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. As of September 30, 2011, we had borrowing capacity of $64.0 million ($330.0 million borrowing base less $266.0 million of outstanding borrowing) under our credit facility. The borrowing base will be redetermined as of May 1 and November 1 of each year, beginning with May 1, 2011, by the administrative agent of our credit facility. On July 13, 2011 we received an interim borrowing base redetermination under our Credit Agreement which increased the borrowing base to $330.0 million. We requested and received this interim redetermination as a result of improvements in our net derivative position due to the buyup of our existing oil fixed price swap contracts in June 2011. On October 3, 2011, in connection with the Acquisition, we amended our Credit Agreement to increase the borrowing base by $300.0 million, resulting in a total borrowing base of $630 million. The administrative agent of our Credit Agreement has accepted this amendment in lieu of our semiannual redetermination required on November 1, 2011. In addition, we may request additional capacity for acquisitions of a minimum of the lesser of $50.0 million or ten percent of then-existing borrowing base.

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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, 2011, we had no letters of credit outstanding.

On October 3, 2011, we entered into an amendment to our Credit Agreement to increase the borrowing base to $630.0 million in conjunction with our purchase of certain oil and gas properties from our Predecessor. We also borrowed an additional $234 million on that date to repay debt assumed from the Predecessor and pay costs associated with the closing of the transaction. These transactions provided us with an additional $66 million in liquidity.

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.4125 per unit per quarter ($1.65 per common unit on an annualized basis). As of September 30, 2011, such annual minimum amounts payable to unitholders approximated $59.2 million.

On October 4, 2011, we announced the board of directors of QRE GP approved an increase in the quarterly cash distribution to all units to $0.4750 per unit, representing a $0.25 annualized increase to $1.90 per unit. This increase will take effect with the cash distribution for the fourth quarter of 2011 payable in February 2012. This increase approximated an additional annual payable to unitholders of $9.0 million.

On October 3, 2011, we issued 16,666,667 Preferred Units to the Fund as payment for the oil and gas properties acquired in the Purchase Agreement. These units will receive an annualized distribution of $0.84 per unit beginning with the cash distribution for the fourth quarter of 2011 payable in February 2012. The annual payable to preferred unitholders will approximate $14.0 million.

Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations above maintenance capital expenditures. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures.

Working Capital. As of September 30, 2011, we had a positive working capital balance of $26.8 million. 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 accrued and other liabilities. 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.

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 to maintain our distributions per unit. For 2011, we have previously estimated our maintenance capital expenditures to be approximately $12.5 million on our asset base as of September 30, 2011. Following the Acquisition, our estimated maintenance capital expenditures are approximately $12.5 million for the fourth quarter of 2011 or approximately $50.0 million on an annual basis. During the nine months ended September 30, 2011, we paid $16.0 million of total capital expenditures primarily related to drilling, capitalized workovers and recompletions.

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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 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. 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 may make acquisitions during the fiscal year ending December 31, 2011, including potential acquisitions of producing properties from the Fund, we have not estimated any growth capital expenditures related to acquisitions, 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 are 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 new credit facility will exceed our planned capital expenditures and other cash requirements for 2011. 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.

For the nine months ended September 30, 2010, our Predecessor’s expenditures were $931.0 million, comprising $895.9 million of acquisition related expenditures, $33.6 million of capital expenditures and $1.5 million of other additions to property and equipment. The Predecessor’s acquisition related expenditures included $892.8 million of payments for the Denbury Acquisition and also $3.1 million of payments for surface acquisitions in a portion of the Jay field.

Credit Agreement

The Credit Agreement provides for a five-year, $750.0 million revolving credit facility, with a borrowing base of $330 million as of September 30, 2011. The borrowing base will be subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, natural gas and NGL reserves, which will take into account the prevailing oil, natural gas and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. On July 13, 2011 we received an interim borrowing base redetermination for our Credit Agreement which increased the borrowing base to $330.0 million.

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 our wholly owned subsidiary, OLLC, and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum.

The Credit Agreement requires us to maintain a leverage ratio (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 (including a prohibition on our ability to pay distribution to our unitholders if our borrowing base usage exceeds 95%); 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 reviewed quarterly financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production from total proved reserves for the next two years and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in our 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, 2011, we were in compliance with the financial covenants of the Credit Agreement.

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As of September 30, 2011, we had $266.0 million of outstanding borrowings under the facility.

On October 3, 2011, we amended our revolving credit facility to, among other things, increase the borrowing base by $300.0 million, resulting in a total borrowing base of $630.0 million. This amendment also modified certain provisions and covenants of to allow for the successful consummation of the transactions related to the Purchase Agreement, the issuance of the Preferred Units and the related entry into the amendment to our partnership agreement (See Note 15). This amendment removes the restriction on our ability to pay distributions to our unitholders based on borrowing base utilization. The administrative agent of our Credit Agreement has accepted this amendment in lieu of our semiannual redetermination required on November 1, 2011.

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 4, “Derivative Activities.”

Cash Flows

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

	Partnership			Predecessor
	Nine Months Ended September 30, 2011			Nine Months Ended September 30, 2010
Net Cash provided by (used in):
Operating activities	$	3,488		$	50,762
Investing activities		(14,712	)		(931,044	)
Financing activities		10,241			884,466

Operating Activities

Our cash flow from operating activities for the nine months ended September 30, 2011 was $3.5 million, comprising a one-time payment of $40.7 million to modify our fixed price swap derivative contracts partially offset by $44.2 million of other net operating cash inflows primarily due to favorable operating margins.

Investing Activities

Our cash flow used in investing activities for the nine months ended September 30, 2011 was $14.7 million comprising $16.0 million of payments made for additions to oil and natural gas properties partially offset by $1.3 million in proceeds from the sales of oil and gas leases.

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Financing Activities

Our cash flow from financing activities for the nine months ended September 30, 2011 was $10.2 million, comprising cash inflows of $83.6 million primarily due to contributions from the underwriters’ exercise of their over-allotment option, in connection with the IPO, and proceeds from bank borrowings to fund the $40.7 million payment to modify our oil fixed price swap derivative contracts. These cash inflows were partially offset by $73.4 million cash outflows primarily due to distributions to the Fund and public unitholders.

Capital Requirements

For 2011, we have estimated our maintenance capital expenditures to develop our oil and natural gas properties to be approximately $12.5 million on our asset base as of September 30, 2011. Following the Acquisition, our estimated maintenance capital expenditures are approximately $12.5 million for the fourth quarter of 2011.

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 2011 through a combination of cash, borrowings under our credit facility, and the issuance of equity securities.

Contractual Obligations

On October 3, 2011 we borrowed an additional $234.0 million in order to repay $227.0 million of debt assumed from the Fund and $7.0 million in estimated transaction fees in connection with our acquisition of certain oil and gas properties from the Fund. This transaction increased our outstanding borrowings on our credit facility to $500.0 million which matures in December 2015. Our level of capital expenditures will vary in the future periods depending on the success we experience in our acquisition, development and exploration 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, 2011, 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 accounting principles generally accepted in the United States. 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 Annual Report.

Item 3. Quantitative and Qualitative Disclosures About market Risk

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, natural gas and natural gas liquids prices by reducing the risk of price volatility and the effect it could have on our operations. The type 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 for the next 12 to 60 months. 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 Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Part I. Item 1. Consolidated Financial Statements (Unaudited)—Note 4, “Derivative Activities” for additional information on our recent derivative transactions.

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We are also exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Periodically, we may look to utilize interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At September 30, 2011, we did have open positions that converted our variable interest rate debt to fixed interest rates on all of our outstanding debt. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

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. See Part I. – Item 1. Consolidated Financial Statements (Unaudited) —Note 3. “Fair Value Measurements” and Part I. - Item 1. Consolidated Financial Statements (Unaudited)—Note 4, “Derivative Activities” for more details.

Item 4. Controls and Procedures

Material Weaknesses in Internal Control over Financial Reporting.

Prior to the completion of our IPO, our Predecessor was a private partnership with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address internal control over financial reporting. Our control environment and control activities are the same as our Predecessor. As previously discussed in Part II - Item 9A. “Controls and Procedures” of our Annual Report, we reported material weaknesses in our overall control environment, as well as numerous material weaknesses at various control activity levels. These material weaknesses continue to exist as of September 30, 2011, the end of the period covered by this report.

Evaluation of Disclosure Controls and Procedures.

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2011. 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. In light of the previously identified material weaknesses described in our Annual Report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of September 30, 2011.

Remediation Plans for Previously Identified Material Weaknesses

We completed our initial review of our internal control processes over financial reporting and have begun implementing processes and controls to remediate the material weaknesses in our internal control over financial reporting. We expect to complete our implementation of processes and testing of internal controls during the fourth quarter of 2011, but cannot predict the outcome of our efforts at this time. During the course of our internal controls testing and remediation process, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weaknesses previously identified. Each of the material weaknesses described in Part II - Item 9A, “Controls and Procedures” of our Annual Report, could result in a misstatement of our accounts or disclosures that would result in a material misstatement of our interim consolidated financial statement that would not be prevented or detected. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to remediate the material weaknesses previously disclosed in our 2010 Annual Report on Form 10-K or avoid potential future material weaknesses.

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Changes in Internal Control over Financial Reporting.

There were no material 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, 2011 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

There have been no material changes to our legal proceedings set forth in Part I-Item 3 “-Legal Proceedings” included in our Annual Report. We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our financial position, results of operations or cash flows for the nine months period ended September 30, 2011.

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the risk factors described in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010 and Part II, Item 1A “Risk Factors” of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011. These risks could materially affect our business, financial condition or future results. There has been no material change in our risk factors from those described in our Annual Report and Quarterly Reports.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

Item 5. Other Information

None.

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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 September 12, 2011, by and among QR Energy, LP, QRE Operating, LLC, Quantum Resources A1, LP, QAB Carried WI, LP, QAC Carried WI, LP, and Black Diamond Resources, LLC (Incorporated herein by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed September 12, 2011).
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		—	Agreement of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.2 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.3		—	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).
3.4		—	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).
3.5		—	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).
3.6		—	Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.5 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.7		—	First Amendment to Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.6 of the Partnership’s Registration Statement on Form S-1/A (File No. 333-169664) filed on November 26, 2010).
3.8		—	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		—	Registration Rights Agreement, dated as of October 3, 2011, by and among QR Energy, LP, Quantum Resources A1, LP, QAB Carried WI, LP, QAC Carried WI, LP, and Black Diamond Resources, LLC (Incorporated herein by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
10.1		—	First Amendment to the Credit Agreement, dated as of October 3, 2011, by and among QR Energy, LP, QRE GP, LLC, QRE Operating, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent and the other lenders party thereto (Incorporated herein by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
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

_____________

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

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

# Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under those sections.

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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 14, 2011	By:	/s/ Alan L. Smith
		Alan L. Smith
		Chief Executive Officer and Director

Dated: November 14, 2011	By:	/s/ Cedric W. Burgher
		Cedric W. Burgher
		Chief Financial Officer

Attached files

QR Energy, LP Reports

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