QR Energy, LP - FORM 10-Q

Attached files

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EX-32.1 - EXHIBIT 32.1 - QR Energy, LP	ex32_1.htm
EX-31.1 - EXHIBIT 31.1 - QR Energy, LP	ex31_1.htm
EX-31.2 - EXHIBIT 31.2 - QR Energy, LP	ex31_2.htm
EX-32.2 - EXHIBIT 32.2 - QR Energy, LP	ex32_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 March 31, 2012

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). x 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 x	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes þ No

As of May 10, 2012, there were 16,666,667 Class C Convertible Preferred Units, 37,422,351 Common Units, 7,145,866 Subordinated Units and 41,747 General Partner Units outstanding.

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PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	4
	Consolidated Balance Sheets as of March 31, 2012 (Unaudited) and December 31, 2011	4
	Unaudited Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011	5
	Unaudited Consolidated Statement of Changes in Partners' Capital for the Three Months Ended March 31, 2012	6
	Unaudited Consolidated Statements of Cash Flow for the Three Months Ended March 31, 2012 and 2011	7
	Unaudited Notes to the Consolidated Financial Statements	8
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	31
Item 4.	Controls and Procedures	31

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 3.	Defaults Upon Senior Securities	32
Item 4.	Mine Safety Disclosures	32
Item 5.	Other Information	32
Item 6.	Exhibits	33

Signatures		34

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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, 2011 and the other disclosures contained herein and therein, which describe known material factors that could cause our actual results to differ from those anticipated in the forward-looking statements, including, but not limited to, the following factors:

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

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

uncertainty inherent in estimating our reserves;

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

cash flows and liquidity;

potential shortages of drilling and production equipment;

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

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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.

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

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PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements.

QR ENERGY, LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

	March 31,			December 31,
	2012			2011
ASSETS	(UNAUDITED)
Current assets:
Cash and cash equivalents	$	21,320		$	17,433
Accounts receivable: oil and gas sales		31,837			32,263
Due from affiliate		-			3,734
Derivative instruments		39,604			32,683
Prepaid and other current assets		314			249
Total current assets		93,075			86,362
Noncurrent assets:
Oil and gas properties, using the full cost method of accounting		1,010,407			975,182
Gas processing equipment		1,644			865
Less accumulated depreciation, depletion, amortization		(100,073	)		(80,484	)
Total property and equipment, net		911,978			895,563
Derivative instruments		60,826			70,570
Deferred taxes		321			290
Other assets		15,574			4,279
Total noncurrent assets		988,699			970,702
Total assets	$	1,081,774		$	1,057,064

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Due to affiliates	$	5,968		$	-
Current portion of asset retirement obligations		322			348
Derivative instruments		20,272			9,569
Accrued and other liabilities		87,632			50,027
Total current liabilities		114,194			59,944
Noncurrent liabilities:
Long-term debt		511,500			500,000
Derivative instruments		24,735			16,906
Asset retirement obligations		66,175			65,353
Deferred taxes		20			20
Total noncurrent liabilities		602,430			582,279
Commitments and contingencies (see Note 10)
Partners' capital:
Class C converible preferred unitholders (16,666,667 issued and outstanding as of March 31, 2012 and December 31, 2011)		361,814			358,138
General partner (35,729 units issued and outstanding as of March 31, 2012 and December 31, 2011)		494			546
Public common unitholders (17,297,351 and 17,292,279 units issued and outstanding as of March 31, 2012 and December 31, 2011)		196,958			241,306
Affiliated common unitholders (11,297,737 units issued and outstanding as of March 31, 2012 and December 31, 2011)		(114,693	)		(113,414	)
Subordinated unitholders (7,145,866 units issued and outstanding as of March 31, 2012 and December 31, 2011)		(79,423	)		(71,735	)
Total partners' capital		365,150			414,841
Total liabilities and partners' capital	$	1,081,774		$	1,057,064

See accompanying notes to the consolidated financial statements

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QR ENERGY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except per unit amounts)

	Three Months Ended
	March 31, 2012			March 31, 2011
Revenues:
Oil and natural gas sales	$	65,329		$	62,353
Processing and other		458			478
Total revenues		65,787			62,831
Operating Expenses:
Production expenses		23,020			19,798
Depreciation, depletion and amortization		19,590			18,909
Accretion of asset retirement obligations		843			648
General and administrative		8,430			6,549
Total operating expenses		51,883			45,904
Operating income		13,904			16,927
Other income (expense):
Realized gains on commodity derivative contracts		8,071			1,309
Unrealized losses on commodity derivative contracts		(21,769	)		(61,605	)
Interest expense, net		(7,472	)		(3,391	)
Total other expense, net		(21,170	)		(63,687	)
Loss before income taxes		(7,266	)		(46,760	)
Income tax benefit, net		31			211
Net loss		(7,235	)		(46,549	)
Net loss per limited partner unit:
Common unitholders' (basic and diluted)	$	(0.49	)	$	(0.82	)
Subordinated unitholders' (basic and diluted)	$	(0.49	)	$	(0.82	)
Weighted average number of limited partner units outstanding:
Common units (basic and diluted)		28,591			28,480
Subordinated units (basic and diluted)		7,146			7,146

See accompanying notes to the consolidated financial statements

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QR ENERGY, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (UNAUDITED)

(In thousands)

							Limited Partners
	Class C Convertible			General			Public			Affiliated						Total
	Preferred Unitholders			Partner			Common			Common			Subordinated			Partners' Capital
Balances - December 31, 2011	$	358,138		$	546		$	241,306		$	(113,414	)	$	(71,735	)	$	414,841
Contributions from the Predecessor		-			-			-			4,268			2,699			6,967
Recognition of unit-based awards		-			-			420			-			-			420
Reduction in units to cover individuals' tax withholding		-			-			(21	)		-			-			(21	)
Accrued distributions to unitholders (see Note 9)		-			(34	)		(36,255	)		-			(6,878	)		(43,167	)
Accrued distribution payable to preferred units		(3,500	)														(3,500	)
Amortization of discount on increasing rate distributions		3,676			-			-			-			-			3,676
Noncash distribution to preferred unitholders		(3,676	)		-			-			-			-			(3,676	)
Management incentive fee earned		-			(3,155	)		-			-			-			(3,155	)
Net loss		7,176			3,137			(8,492	)		(5,547	)		(3,509	)		(7,235	)
Balances - March 31, 2012	$	361,814		$	494		$	196,958		$	(114,693	)	$	(79,423	)	$	365,150

See accompanying notes to consolidated financial statements

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QR ENERGY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

	Three Months Ended
	March 31, 2012			March 31, 2011
Cash flows from operating activities:
Net loss	$	(7,235	)	$	(46,549	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		19,590			18,909
Accretion of asset retirement obligations		843			648
Amortization of deferred financing costs		266			421
Recognition of unit-based awards		420			345
General and administrative expense contributed by affiliates		6,967			2,324
Unrealized losses on derivative contracts		21,355			60,747
Deferred income tax benefit		(31	)		(286	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		4,094			(23,544	)
Accounts payable and other liabilities		5,073			5,219
Net cash provided by operating activities		51,342			18,234
Cash flows from investing activities:
Additions to oil and gas properties		(26,910	)		(12,460	)
Acquisition deposit		(11,500	)		-
Net cash used in investing activities		(38,410	)		(12,460	)
Cash flows from financing activities:
Proceeds from underwriters' exercise of overallotment option		-			41,963
Distributions to the Fund		-			(42,000	)
Contributions from the General Partner		-			715
Distributions to unitholders		(20,545	)		(1,607	)
Contributions from the Predecessor		-			(5,063	)
Proceeds from bank borrowings		11,500			-
Deferred financing costs		-			(147	)
Net cash used in financing activities		(9,045	)		(6,139	)
Increase (decrease) in cash and cash equivalents		3,887			(365	)
Cash and cash equivalents at beginning of period		17,433			2,195
Cash and cash equivalents at end of period	$	21,320		$	1,830

See accompanying notes to the 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 the affiliated entity, QA Holdings, LP (the “Predecessor”) and own other assets. 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, or $18.70 per unit after taking into account the underwriting discount. On the Closing Date, a Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) was executed by and among the Fund, the Partnership and QRE GP with net assets contributed by the Fund. In exchange for the net assets, the Fund received 11,297,737 common and 7,145,866 subordinated limited partner units. QRE GP made a capital contribution to the Partnership in exchange for 35,729 general partner units.

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

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

On March 19, 2012, we entered into a Purchase and Sale Agreement (the “Purchase Agreement”), with Prize Petroleum, LLC and Prize Petroleum Pipeline, LLC for the acquisition of primarily oil properties (the “Prize Acquisition”) for approximately $230 million, subject to customary purchase price adjustments. The properties are located primarily in the Ark-La-Tex area. We placed into escrow a deposit of $11.5 million, equal to 5 percent of the purchase price, in accordance with the Purchase Agreement, which is recorded in other assets as of March 31, 2012. The Prize Acquisition closed on April 20, 2012. Refer to Note 15 – Subsequent Events for further details.

On March 26, 2012, we filed a registration statement with the United States Securities and Exchange Commission (the “SEC”) for the public offering of common units representing limited partnership interests in us. Additionally, included in the registration statement were 17,500,000 common units, including 6,202,263 common units to be issued by us, and 11,297,731 common units owned by the Fund, all of which were offered for sale to the public. In conjunction with the offering, the Partnership granted the underwriters an over-allotment option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership. The offering closed on April 17, 2012 and the common units, including the units pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. For more information, see Note 15 – Subsequent Events for further details.

At March 31, 2012, our ownership structure comprised a 0.1% general partner interest held by QRE GP, a 66.9% limited partner interest held by the Fund and a 33.0% limited partner interest held by the public unitholders.

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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 for complete annual financial statements. During interim periods, the Partnership follows the accounting policies disclosed in its 2011 Annual Report on Form 10-K, filed with the SEC. The unaudited consolidated financial statements for the three months ended March 31, 2012 and 2011 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. Operating results for the three month period ended March 31, 2012 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2012. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report for the year ended December 31, 2011.

The Partnership’s historical financial statements previously filed with the SEC have been revised in this quarterly report on Form 10-Q to include the results attributable to the Transferred Properties as if the Partnership owned such assets for all periods presented by the Partnership including the period from January 1, 2011 to March 31, 2011 as the Transaction was between entities under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the Transferred Properties have been prepared from the Predecessor’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. See our accounting policy for transactions between entities under common control set forth in Note 2 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2011.

Accounting Policy Updates/Revisions

The accounting policies followed by the Partnership are set forth in Note 2 – Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2011. There have been no significant changes to these policies during the three months ended March 31, 2012.

Recent Accounting Pronouncements

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

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

NOTE 3 – 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). US GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of fair value hierarchy are as follows:

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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 –

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

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

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

Long-Term Debt — The fair value of our long term debt depends primarily on the current active market LIBOR. The carrying value of our long term debt as of March 31, 2012 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.

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 March 31, 2012 and December 31, 2011.

As of March 31, 2012	Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	100,430	$	-	$	100,430	$	-
Assets from interest rate derivative instruments		-		-		-		-
	$	100,430	$	-	$	100,430	$	-

Liabilities from commodity derivative instruments	$	21,469	$	-	$	21,468	$	-
Liabilities from interest rate derivative instruments		23,538		-		23,539		-
	$	45,007	$	-	$	45,007	$	-

As of December 31, 2011	Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	103,233	$	-	$	103,233	$	-
Assets from interest rate derivative instruments		20		-		20		-
	$	103,253	$	-	$	103,253	$	-

Liabilities from commodity derivative instruments	$	2,502	$	-	$	2,502	$	-
Liabilities from interest rate derivative instruments		23,973		-		23,973		-
	$	26,475	$	-	$	26,475	$	-

There have been no transfers between levels within the fair value measurement hierarchy during the three months ended March 31, 2012.

NOTE 4 – DERIVATIVE ACTIVITIES

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

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

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Commodity Derivatives

Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. As such, future earnings are subject to fluctuations due to changes in the market price of oil, 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.

During the three months ended March 31, 2012 we entered into new oil swap and collar contracts ranging from 2012 through 2017. All of the new contracts were entered into with the same counterparties as our existing contracts.

We hold commodity derivative contracts to manage our exposure to changes in the price of oil and natural gas related to our oil and natural gas production. As of March 31, 2012, the notional volumes of our commodity derivative contracts were:

Commodity	Index	Apr 1 - Dec 31, 2012			2013			2014			2015			2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		5,781			6,543			5,661			4,540			1,870		1,580
Average price ($/Bbls)		$	100.20		$	99.75		$	97.91		$	96.87		$	94.38	$	92.33
Collars
Hedged Volume (Bbls/d)	WTI								425			1,025			1,500
Average floor price ($/Bbls)								$	90.00		$	90.00		$	80.00
Average ceiling price ($/Bbls)								$	106.50		$	110.00		$	102.00

Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	NYMEX		30,296			29,674			25,907			6,100
Average price ($/MMBtu)		$	5.81		$	6.07		$	6.23		$	5.52
Basis Swaps
Hedged Volume (MMBtu/d)	NYMEX		20,718			18,466			17,066			14,400
Average price ($/MMBtu)		$	(0.15	)	$	(0.17	)	$	(0.19	)	$	(0.19	)
Collars
Hedged Volume (MMBtu/d)	Henry Hub		2,618			2,466			4,966			18,000
Average floor price ($/MMBtu)		$	6.50		$	6.50		$	5.74		$	5.00
Average ceiling price ($/MMBtu)		$	8.60		$	8.65		$	7.51		$	7.48

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Interest Rate Derivatives

In an effort to mitigate exposure to changes in market interest rates, we have entered into interest rate swaps that effectively fix the LIBOR component on our outstanding debt. The changes in the fair value of these instruments are recorded in current earnings.

The fair value of these derivatives was as follows as of the dates indicated:

	March 31, 2012				December 31, 2011
	Asset		Liability		Asset		Liability
	Derivatives		Derivatives		Derivatives		Derivatives

Commodity contracts	$	100,430	$	21,469	$	103,233	$	2,502
Interest rate contracts		-		23,538		20		23,973
	$	100,430	$	45,007	$	103,253	$	26,475

Commodity
Current	$	39,604	$	11,393	$	32,683	$	1,284
Noncurrent		60,826		10,076		70,550		1,218
	$	100,430	$	21,469	$	103,233	$	2,502
Interest
Current	$	-	$	8,879	$	-	$	8,285
Noncurrent		-		14,659		20		15,688
	$	-	$	23,538	$	20	$	23,973

Total Derivatives
Current	$	39,604	$	20,272	$	32,683	$	9,569
Noncurrent		60,826		24,735		70,570		16,906
	$	100,430	$	45,007	$	103,253	$	26,475

The following table presents the impact of derivatives and their location within our unaudited consolidated statements of operations for the periods ended March 31, 2012 and March 31, 2011:

	Three Months ended March 31,
	2012			2011
Realized gains (losses):
Commodity contracts (1)	$	8,071		$	1,309
Interest rate swaps (2)		(2,303	)		(314	)
Total	$	5,768		$	995

Unrealized gains (losses):
Commodity contracts (1)	$	(21,769	)	$	(61,605	)
Interest rate swaps (2)		414			858
Total	$	(21,355	)	$	(60,747	)

Total gains (losses):
Commodity contracts (1)	$	(13,698	)	$	(60,296	)
Interest rate swaps (2)		(1,889	)		544
Total	$	(15,587	)	$	(59,752	)

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

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

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NOTE 5 – INCOME TAXES

The Partnership does not pay federal income taxes as its profits or losses are reported to the taxing authorities by the individual partners.

The Partnership pays Texas Margin Tax. The Partnership has recorded a deferred tax asset of $0.3 million and $0.3 million related to its operations located in Texas as of March 31, 2012 and December 31, 2011. The Partnership has recorded a current tax liability of less than $0.1 million as of March 31, 2012 and December 31, 2011 which is included in noncurrent liabilities on the consolidated balance sheet. The deferred tax asset is included in noncurrent assets on the consolidated balance sheet. The Partnership’s provision for income taxes was a net benefit of less than $0.1 million and $0.2 million for the three months ended March 31, 2012 and March 31, 2011.

NOTE 6 – ASSET RETIREMENT OBLIGATIONS

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

Changes in our asset retirement obligations for the three months ended March 31, 2012 are presented in the following table:

	Three months ended
	March 31,
	2012
Beginning of period	$	65,701
Revisions to previous estimates		528
Liabilities incurred		-
Liabilities settled		(575	)
Accretion expense		843
End of period	$	66,497
Less: Current portion of asset retirement obligations		(322	)
Asset retirement obligations -non-current	$	66,175

NOTE 7 – ACCRUED AND OTHER LIABILITIES

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

	March 31, 2012		December 31, 2011
Distributions payable (1)	$	46,667	$	20,545
Accrued capital spending		16,421		9,591
Production expense accrual		14,904		12,872
Other		9,640		7,019
	$	87,632	$	50,027

(1)

As of March 31, 2012, the distribution payable includes distributions for the first and second quarters of 2012 which were declared by the board of directors of QRE GP on March 29, 2012. See Note 9 – Partners’ Capital for details.

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NOTE 8 – LONG-TERM DEBT

Revolving Credit Facility

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

As of March 31, 2012, we had $511.5 million of borrowings outstanding and $0.4 million of letters of credit outstanding resulting in $118.1 million of borrowing availability. As of December 31, 2011, we had $500 million of borrowings and $0.4 million letters of credit outstanding resulting in $129.6 million of borrowing availability. In conjunction with the Prize Acquisition, we had additional borrowings of approximately $65 million in April 2012. We also had additional borrowings of $5.0 million in May 2012. As of May 10, 2012, we had $581.5 million of borrowings outstanding.

The Credit Agreement provides for a five-year, $750.0 million revolving credit facility maturing on December 22, 2015, with a borrowing base of approximately $630.0 million as of March 31, 2012. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ price assumptions, and other various factors unique to each member bank. Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum.

The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and also requires us to provide audited financial statements within 90 days of year end and quarterly 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 reserves to be acquired and (ii) 85% of our forecasted production for the next two years from total proved reserves and total proved reserves to be acquired and 75% of our forecasted production from total proved reserves and total proved reserves to be acquired thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of March 31, 2012, we were in compliance with all of the Credit Agreement covenants.

In contemplation of the Prize Acquisition, we entered into a Second Amendment to the Credit Agreement on March 16, 2012 to provide for additional derivative contracts to cover production of proved reserves to be acquired, as discussed above.

In April 2012, we entered into the Third Amendment to the Credit Agreement, which became effective upon the closing of the Prize Acquisition. Pursuant to the Third Amendment our credit facility was increased from $750 million to $1.5 billion, our borrowing base was increased from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017. In addition, our margins were amended whereby 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 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to an amended commitment fee that varies from 0.375% to 0.50% per annum. Refer to Note 15 – Subsequent Events for further details.

Bridge Loan Commitment

In conjunction with the Prize Acquisition, we entered into a secured commitment (the “Bridge Loan Commitment”) to provide an additional $200 million of bank loans to fund the acquisition as needed. We did not utilize any borrowings under the commitment and as of May 10, 2012 the Bridge Loan Commitment has been terminated by us. We incurred $1.6 million of commitment fees related to the Bridge Loan Commitment which were recorded in interest expense for the three months ended March 31, 2012.

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NOTE 9 — PARTNERS’ CAPITAL

Units Outstanding

The table below details the units outstanding as of March 31, 2012 and December 31, 2011, and the changes in outstanding units for the three months ended March 31, 2012. As of March 31, 2012, the fund owned all preferred units, 11,297,737 common units (which were sold in April 2012 as described in Note 15-Subsequent Events) and all subordinated units.

			General					Affiliated
	Prefer red Units		Partner		Public Common			Common		Subordinated
Balance - December 31, 2011		16,666,667		35,729		17,292,279			11,297,737		7,145,866
Vested units awarded under our Long Term Incentive Performance Plan		-		-		5,990			-		-
Reduction in units to cover individuals'tax witholdings		-		-		(918	)		-		-
Balance - March 31, 2012		16,666,667		35,729		17,297,351			11,297,737		7,145,866

Allocations of Net Income (Loss)

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

Cash Distributions

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

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

As of March 31, 2012, QRE GP owns a 0.1% general partner interest in us, represented by 35,729 general partner units. QRE GP has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. QRE GP’s initial 0.1% interest in these distributions will be reduced if we issue additional units in the future and QRE GP does not contribute a proportionate share of capital to us to maintain its 0.1% general partnership interest.

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

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On March 29, 2012, the board of directors of QRE GP approved a $0.475 per unit distribution for the quarter ended March 31, 2012 on all limited partner units. The distribution is to be paid on May 11, 2012 to unitholders of record at the close of business on April 30, 2012. Preferred unitholders will receive a distribution for the quarter ended March 31, 2012 of $0.21 per unit in accordance with the Partnership Agreement. The aggregate amount of the first quarter common and preferred unit holder distribution accrued, as of March 31, 2012, was $24.8 million.

On March 29, 2012, the board of directors of QRE GP approved an increase to the quarterly cash distributions beginning with the second quarter of 2012 to $0.4875 per unit, contingent on the closing of the Prize Acquisition. On the same date, the $0.4875 per unit cash distribution for the second quarter 2012 was declared and will be payable on August 10, 2012 to unitholders of record at the close of business on July 30, 2012. The contingency was met with the closing of the Prize Acquisition on April 20, 2012, refer to Note 15 – Subsequent Events for details, and as a result, we accrued $21.9 million for the second quarter 2012 common unitholder distribution as of March 31, 2012.

Distribution activities are as follows:

								Limited Partners
	For the	Distributions to		Distributions per		General		Public		Affiliated				Total Distributions		Distributions
Payment Date	period ended	Preferred Unitholders		Preferred Unit (1)		Partner		Common		Common		Subordinated		to Other Unitholders		per other units
(In thousands, except per unit amounts)
February 10, 2012	December 31, 2011		3,424	$	0.2054		16		8,344		5,368		3,393		17,121		0.4750
May 11, 2012	March 31, 2012		3,500	$	0.21		17		17,892		-		3,394		21,303		0.4750
August 10, 2012	June 30, 2012						17		18,363		-		3,484		21,864		0.4875

(1)

Preferred units paid in February 2012 were prorated a quarterly distribution for the portion of the fourth quarter beginning on October 3, 2011 through December 31, 2011 in accordance with the Partnership Agreement. The second quarter preferred unit distribution will be accrued at June 30, 2012 in accordance with the Partnership Agreement.

NOTE 10 – COMMITMENTS AND CONTINGENCIES

Services Agreement

We have entered into a services agreement (the “Service Agreement”) with QRM as described in Note 13 – Related Party Transactions, under which QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. The Partnership has no other commitments as of March 31, 2012.

Legal Proceedings

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

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NOTE 11 – NET INCOME/LOSS PER LIMITED PARTNER UNIT

The following sets forth the calculation of net loss per limited partner unit for the three months ended March 31, 2012 and 2011:

	Three months ended			Three months ended
	March 31, 2012			March 31, 2011
Net loss	$	(7,235	)	$	(46,549	)
Net loss attributable to predecessor operations		-			17,201
Distribution on Class C convertible preferred units		(3,500	)		-
Amortization of preferred unit discount		(3,676	)		-
Net loss available to other unitholders		(14,411	)		(29,348	)
Less: general partner's interest in net loss		3,137			(29	)
Limited partners' interest in net loss	$	(17,548	)	$	(29,319	)
Common unitholders' interest in net loss	$	(14,039	)	$	(23,451	)
Subordinated unitholders' interest in net loss	$	(3,509	)	$	(5,868	)
Net loss per limited partner unit:
Common unitholders' (basic and diluted)	$	(0.49	)	$	(0.82	)
Subordinated unitholders' (basic and diluted)	$	(0.49	)	$	(0.82	)
Weighted average number of limited partner units outstanding(1):
Common units (basic and diluted)		28,591			28,480
Subordinated units (basic and diluted)		7,146			7,146

Total Common/Subordinated units		35,741			35,626

(1)

For the three months ended March 31, 2012, we had weighted average preferred units outstanding of 16,666,667, which are contingently convertible. These units could potentially dilute earnings per unit in the future and have not been included in the earnings per share calculation for the three months ended March 31, 2012, as they were antidilutive for the period.

Net loss per limited partner unit is determined by dividing the net loss available to the limited partner unitholders, after deducting QRE GP’s 0.1% interest in net loss, by the weighted average number of limited partner units outstanding during the three months ended March 31, 2012. We had 28,595,088 common units and 7,145,866 subordinated units outstanding as of March 31, 2012.

NOTE 12 – UNIT-BASED COMPENSATION

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

We recognize the expense related to unvested restricted units using a straight-line amortization method over the vesting period of the award. For the three months ended March 31, 2012 and the three months ended March 31, 2011, we recognized compensation expense related to these awards of $0.4 million and $0.3 million. As of March 31, 2012, we had 244,129 restricted unit awards outstanding and 5,990 vested common units with remaining unamortized costs which had a combined $5.6 million unamortized grant date fair value, which we expect will be recognized in expense over a weighted average period of approximately three years.

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The following table summarizes our unit-based awards for the three months ended March 31, 2012 (in units and dollars):

	Number of			Weighted
	Unvested			Average
	Restricted			Grant-Date
	Units			Fair Value
	(in thousands)
Unvested units, December 31, 2011		271		$	20.26
Granted		1			20.90
Forfeited		(22	)		20.20
Vested		(6	)		22.26
Unvested units, March 31, 2012		244		$	20.29

Note 13 – RELATED PARTY TRANSACTIONS

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

As of March 31, 2012 and December 31, 2011, affiliates of the Fund owned 100% of QRE GP, an aggregate 67% limited partner interest in us represented by 11,297,737 of our common units and all of our preferred and subordinated units. In addition, QRE GP owned a 0.1% general partner interest in us, represented by 35,729 general partner units.

Contracts with QRE GP and its Affiliates

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

Services Agreement

Under the Services Agreement, until December 31, 2012, QRM will be entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA generated by us during the preceding quarter, calculated prior to the payment of the fee. For the three months ended March 31, 2012 and for the three months ended March 31, 2011, we were charged us $1.7 million and $0.8 million in administrative services fee in accordance with the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM.

In connection with the management of our business, QRM provides services for invoicing and collection of our revenues as well as processing of payments to our vendors. Periodically QRM remits cash to us for the net working capital received on our behalf. Changes in the affiliate (payable)/receivable balances during the three months ended March 31, 2012 from the year ended December 31, 2011 are included below:

Net affiliate receivable as of December 31, 2011		3,734
Revenues and other increases (1)		60,462
Expenditures		(47,064	)
Settlements from the Fund		(23,100	)
Net affiliate payable as of March 31, 2012	$	(5,968	)

(1)

Includes $0.9 million in overhead producing credits.

Other Contributions to Partners’ Capital

Other contributions to partners’ capital for the three months ended March 31, 2012 include non-cash general and administrative expense of $7.0 million contributed by the Fund, which represents our share of allocable general and administrative expenses incurred by QRM on our behalf but not reimbursable by us.

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Management Incentive Fee

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

●

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

●

adjusted for our commodity derivative contracts; and

●

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

For the three months ended March 31, 2012, the management incentive fee earned by QRE GP was $3.2 million. For the three months ended March 31, 2011, no management incentive fee was earned by or paid to our general partner.

Long–Term Incentive Plan

The Plan provides compensation to employees, officers, consultants and directors of QRE GP and those of its affiliates, including QRM, who perform services for us. As of March 31, 2012 and December 31, 2011, 244,129 and 271,364 restricted unit awards with a fair value of $5.6 million and $4.8 million were granted under the Plan. For additional discussion regarding the Plan see Note 12 – Unit-Based Compensation.

Distributions of Available Cash to QRE GP and Affiliates

We generally make cash distributions to our unitholders pro rata, including QRE GP and its affiliates. As of March 31, 2012 and December 31, 2011, QRE GP and its affiliates held 11,297,737 common units, all of the subordinated units and 35,729 QRE GP units. The Partnership paid a cash distribution on February 10, 2012 for the quarter ended December 31, 2012 and declared a first quarter 2012 distribution payable on May 11, 2012. The Partnership also declared a cash distribution for the second quarter 2012 payable on August 10, 2012. Refer to Note 9 – Partners’ Capital for details on the distributions.

Our Relationship with Bank of America

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

NOTE 14 – SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended
	March 31, 2012		March 31, 2011
Supplemental Cash Flow Information
Cash paid during the period for interest	$	6,088	$	3,303
Non-cash Investing and Financing Activities
Change in accrued capital expenditures		8,566		1,987
Revision to asset retirement obligation		528		-
Interest rate swaps novated from the Fund		-		2,875
General and admistrative expense allocated from the Fund		6,967		2,324
Accrued distributions (2)		46,667		-
Management incentive fee incurred		3,155		-
Amortization of increasing rate distributions(1)		3,676		-

(1)

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

(2)

Includes distributions for the first and second quarters of 2012 which were declared by the board of directors of QRE GP on March 29, 2012. See Note 9 – Partners’ Capital for details.

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NOTE 15 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after March 31, 2012, up until the issuance of the financial statements.

On April 11, 2012, we entered into the Third Amendment to our Credit Agreement dated December 17, 2010 whereby our credit facility was increased from $750 million to $1.5 billion, our borrowing base was increased from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017. The amendment to the revolving credit facility also modified certain provisions and covenants for the successful consummation of the Prize Acquisition. In conjunction with the Prize Acquisition, we had additional borrowings of $65 million in April 2012. We had additional borrowings of $5 million in May 2012 as described in Note 8 – Long-term Debt.

On April 17, 2012, the Partnership issued 6,202,263 common units representing limited partnership interests in us, and the Fund sold 11,297,737 of common units it held in us, previously registered under a registration statement filed with the SEC on March 26, 2012, for $19.18 per unit to the public. Net proceeds received by the partnership were $114.2 million after the underwriter discount. The Partnership did not receive any proceeds from the sale of the common units sold by the Fund. On April 13, 2012 the underwriters exercised in full their over-allotment option to purchase an additional 2,625,000 common units at a price to the public of $19.18 per unit.

On April 20, 2012, we completed the Prize Acquisition pursuant to the Purchase Agreement entered into on March 19, 2012, with an effective date of January 1, 2012, for $226 million after customary purchase price adjustments. The Prize Acquisition was financed with cash on hand and additional borrowings under the Partnership’s Credit Agreement. As of May 10, 2012, the fair value assessment of the assets acquired has not been completed.

On April 25, 2012, QRE GP purchased 6,018 of general partner units in order to maintain their 0.1% ownership percentage in us. The units were purchased at a price of $19.18 per unit.

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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 in Part II—Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2011 (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 I—Item 1A “Risk Factors” of this report and the “Cautionary Statement Regarding Forward-Looking Information” in this report and in our Annual Report.

Overview

QR Energy, LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed on September 20, 2010, to own and acquire producing oil and natural gas properties in North America. Certain of affiliated entity QA Holdings LP’s (the Predecessor”) 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”).

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploitation activities or acquire properties with existing production. The amount we realize for our production depends predominately upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differential and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Results of Operations

Because affiliates of the Fund own 100% of our general partner and an aggregate 67% limited partner interest in us including 11,297,737 of our common units and all of our preferred and subordinated units as of March 31, 2012, each acquisition of assets from the Predecessor is considered a transfer of net assets between entities under common control. As a result, we are required to revise our financial statements to include the activities of such assets for all periods presented by the Partnership, similar to a pooling of interests, to include the financial position, results of operations, and cash flows of the assets acquired and liabilities assumed. The table set forth below includes the recast historical financial information for the three months ended March 31, 2011 as if the acquired assets were owned by us for all periods presented for the Partnership. These results are presented for illustrative purposes only and are not indicative of future results of the Partnership.

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	Three Months Ended
	March 31, 2012			March 31, 2011 (1)

Revenues: (2)
Oil sales	$	45,800		$	39,664
Natural gas sales		11,901			16,269
NGLs sales		7,628			6,420
Processing and other		458			478
Total Revenue		65,787			62,831
Operating Expenses:
Lease operating expenses		17,459			14,309
Production and other taxes		4,711			4,268
Processing and transportation		850			1,221
Total production expenses		23,020			19,798
Depreciation, depletion and amortization		19,590			18,909
Accretion of asset retirement obligations		843			648
General and administrative and other		8,430			6,549
Total operating expenses		51,883			45,904
Operating income		13,904			16,927
Other income (expense):
Realized gains on commodity derivative contracts		8,071			1,309
Unrealized losses on commodity derivative contracts		(21,769	)		(61,605	)
Interest expense, net		(7,472	)		(3,391	)
Total other expense, net		(21,170	)		(63,687	)
Loss before income taxes		(7,266	)		(46,760	)
Income tax benefit		31			211
Net loss	$	(7,235	)	$	(46,549	)
Production data (3):
Oil (MBbls)		454			428
Natural gas (MMcf)		3,638			4,000
Natural gas liquids (MBbls)		174			180
Total (Mboe)		1,234			1,275
Average Net Production (Boe/d)		13,564			14,167
Average sales price per unit (4):
Oil (Per Bbl)	$	100.88		$	92.67
Natural gas (per Mcf)	$	3.36		$	4.19
Natural gas liquids (Per Bbl)	$	54.88		$	46.53
Average unit cost per Boe:
Lease operating expense	$	14.14		$	11.23
Production and other taxes	$	3.82		$	3.35
Depreciation, depletion and amortization	$	15.87		$	14.83
General and administrative expenses	$	6.83		$	5.14

(1)

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

(2)

Certain natural gas liquid sales for the three months ended March 31, 2011 have been reclassified from natural gas sales to conform to current presentation. This resulted in an increase in natural gas liquid sales and a decrease in natural gas sales of $4.5 million and an increase in natural gas liquid volumes of 96 MBbls and a decrease in natural gas volumes of 576 MMcf.

(3)

Includes certain volumes for natural gas (91 MMcf for 2012 and 119 MMcf for 2011) and natural gas liquids (35 MBbls for 2012 and 42 MBbls for 2011) for which revenues were reported on a net basis.

(4)

Does not include the impact of derivative instruments.

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Results of Operations

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

We recorded a net loss of $7.2 million for the three months ended March 31, 2012 compared to a net loss of $46.5 million for the three months ended March 31, 2011. This change was primarily driven by a decline in unrealized losses on commodity derivative contracts of $39.8 million.

Revenues:

	Three Months Ended March 31,
					Increase			Precentage
	2012		2011		(Decrease)			Change
Production:
Oil (MBbls)		454		428		26			6	%
Natural Gas (MMcf)		3,638		4,000		(362	)		-9	%
NGL (MBbl)		174		180		(6	)		-3	%
Total (Mboe)		1,234		1,275		(41	)		-3	%

Average sales prices per unit:
Oil (per Bbl)	$	100.88	$	92.67	$	8.21			9	%
Natural Gas (per Mcf)		3.36		4.19		(0.83	)		-20	%
NGL (per Bbl)		54.88		46.53		8.35			18	%
Total (per Boe)		52.94		48.90		4.04			8	%

Revenues:
Oil sales	$	45,800	$	39,664	$	6,136			15	%
Natural Gas sales		11,901		16,269		(4,368	)		-27	%
NGL sales		7,628		6,420		1,208			19	%
Total revenue	$	65,329	$	62,353	$	2,976			5	%

Total revenue increased by $3.0 million to $65.3 million for the three months ended March 31, 2012 due to higher sales prices per Boe mainly attributed to increased prices for oil and natural gas liquids offset by lower prices for natural gas, despite a slight decrease in the total production volumes of 41 Mboe. Our production for the three months ended March 31, 2012 has remained relatively constant due to our capital and maintenance programs.

Production Expenses. Our production expense for the three months ended March 31, 2012 increased to $23.0 million from $19.8 million for the three months ended March 31, 2011, consisting mainly of an increase in lease operating expenses to $17.5 million, or $14.14 per Boe, for the three months ended March 31, 2012 from $14.3 million, or $11.23 per Boe for the three months ended March 31, 2011, and an increase in production and other taxes to $4.7 million, or $3.82 per Boe, from $4.3 million, or $3.35 per Boe for the three months ended March 31, 2011. The increase in production expenses is mainly attributed to the activation of lower margin wells during the last twelve months as compared to the three months ended March 31, 2011, as well as increased costs associated with the maintenance of our existing wells.

Depreciation, Depletion and Amortization Expenses. For the three months ended March 31, 2012 our depreciation, depletion and amortization expenses were $19.6 million, or $15.87 per Boe as compared to $18.9 million, or $14.83 per Boe for the three months ended March 31, 2011. The increase in depreciation, depletion and amortization (“DD&A”) is due to higher estimates of future development costs to maintain our production levels relative to our proved reserves in the three months ended March 31, 2012 as compared to the three months ended March 31, 2011.

General and Administrative and Other Expenses. For the three months ended March 31, 2012 our general and administrative and other expenses increased to $8.4 million, or $6.83 per Boe, as compared to $6.5 million, or $5.14 per Boe for the three months ended March 31, 2011. The increase is mainly attributed to the increase in our costs associated with fully staffing our organization. These expenses are incurred and allocated to us by QRM, but are not reimbursable by us.

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Effects of Commodity Derivative Contracts. For the three months ended March 31, 2012, our unrealized loss on commodity derivative contracts decreased to $21.8 million for the three months March 31, 2012 from $61.6 million for the three months ended March 31, 2011. Unrealized gains and losses result from changes in the future commodity prices as compared to the fixed price of our open commodity derivative contracts. The significant reduction in our unrealized losses was primarily due to the modification of our existing oil fixed priced swap derivative contracts in the second and third quarter of 2011, as well as the decline in future prices for natural gas.

Interest Expense, net. Net interest expense increased to $7.5 million for the three months ended March 31, 2012 as compared to $3.4 million for the three months ended March 31, 2011. The increase is primarily due to an increase in realized losses on interest rate derivative contracts of $2.0 million, coupled with the $1.6 million commitment fee related to the Bridge Loan Commitment incurred in the three months ended March 31, 2012.

Liquidity and Capital Resources

Our cash flow from operating activities for the three months ended March 31, 2012 was $51.3 million.

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.

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

As of March 31, 2012, our liquidity of $139.4 million consisted of $21.3 million of available cash and $118.1 million of availability under our credit facility after giving consideration to $0.4 million of outstanding letters of credit. As of March 31, 2012, we had $511.5 million of borrowings outstanding. In conjunction with the Prize Acquisition, we had additional borrowings of approximately $65 million in April 2012. We also had additional borrowings of $5.0 million in May 2012. As of May 10, 2012 we had $581.5 million of borrowings outstanding with borrowing availability of $148.1 million ($730.0 million borrowing base less $581.5 million of outstanding borrowing and $0.4 million of outstanding letters of credit) under our credit facility. The borrowing base is redetermined as of May 1 and November 1 of each year. The administrative agent of our Credit Agreement has accepted the Third Amendment to the Credit Agreement in lieu of our May 1 redetermination with the next determination on November 1, 2012. In addition, we may request additional capacity for acquisitions of a minimum of the lesser of $50 million or ten percent of the then-existing borrowing base. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility.

A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands. As of March 31, 2012, we had letters of credit in the amount of $0.4 million outstanding for utilities.

On April 11, 2012, the Partnership issued 6,202,263 common units representing limited partnership interests in us and the Fund sold 11,297,737 of common units it held in us, previously registered under a registration statement filed with the SEC on March 26, 2012, for $19.18 per unit to the public. Net proceeds received by the partnership were $114.2 million after the underwriter discount. The Partnership did not receive any proceeds from the sale of the common units sold by the Fund. On April 13, 2012 the underwriters exercised in full their over-allotment option to purchase an additional 2,625,000 common units at a price to the public of $19.18 per unit. The proceeds were used for the Prize Acquisition and reduction in outstanding borrowings.

We announced that our general partner declared cash distributions to our common and subordinated unitholders and our general partner at the first quarter 2012 distribution rate of $0.4750 per unit and the second quarter rate of $0.4875 per unit ($1.95 per common unit on an annualized basis for the year 2012). We intend to make cash distributions to our preferred unitholders at least at the minimum quarterly distribution rate of $0.21 per unit per quarter ($0.84 per preferred unit on an annualized basis) in accordance with the Partnership Agreement. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources.

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

As of March 31, 2012, we had a negative working capital balance of $21.1 million due to the accrual of the second quarter 2012 distribution of $21.9 million payable on August 10, 2012 and the increase in capital spending accruals related to our first quarter 2012 drilling program. This does not preclude the Partnership from meeting its short-term obligations.

Capital Expenditures

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage). The primary purpose of maintenance capital is to maintain our production and asset base at a steady level over the long term in order to maintain our distributions per unit. For 2012, we have estimated our maintenance capital expenditures to be approximately $51.3 million. During the three months ended March 31, 2012, we have expended $26.9 million of total capital expenditures.

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 closed the Prize Acquisition in April 2012, as discussed in Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 15, Subsequent Events, we cannot estimate further growth capital expenditures related to acquisitions, including potential acquisitions of producing properties from the Fund, as we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts.

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

Credit Facilities

Revolving Credit Facility

As of March 31, 2012, we are party to a five-year credit agreement that governs our $750.0 million revolving credit facility with a current borrowing base of $630.0 million. The borrowing base is subject to redetermination on a semi-annual and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ price assumptions, and other various factors unique to each member bank. In the future, we may be unable to access sufficient capital under our new credit facility as a result of (i) a decrease in our borrowing base due to subsequent borrowing base redeterminations, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

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

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Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum.

The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and to provide audited financial statements within 90 days of year end and quarterly 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 reserves to be acquired and (ii) 85% of our forecasted production for the next two years from total proved reserves and total proved reserves to be acquired and 75% of our forecasted production from total proved reserves and total proved reserves to be acquired thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of March 31, 2012, we were in compliance with all of the Credit Agreement covenants.

In contemplation of the Prize Acquisition, we entered into a Second Amendment to the Credit Agreement to provide for additional derivative contracts to cover production of proved reserves to be acquired as, discussed above.

In April 2012, we entered into the Third Amendment to the Credit Agreement whereby our credit facility was increased from $750 million to $1.5 billion, our borrowing base was increased from $630 million to $730 million, and the maturity date was extended from December 22, 2015 to April 20, 2017. In addition, our margins were amended whereby 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 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to an amended commitment fee that varies from 0.375% to 0.50% per annum. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 15, Subsequent Events.

As of March 31, 2012 and May 10, 2012, we had $511.5 million and $581.5 million of outstanding borrowings under the credit facility.

Bridge Loan Commitment

In conjunction with the Prize Acquisition, we entered into a Bridge Loan Commitment to provide an additional $200 million of bank loans to fund the acquisition as needed. We did not utilize any borrowings under the commitment and as of May 10, 2012 the Bridge Loan Commitment has been terminated by us. We incurred $1.6 million of commitment fees related to the Bridge Loan Commitment which were recorded in interest expense for the three months ended March 31, 2012.

Commodity Derivative Contracts

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on the prices of oil and natural gas and our ability to maintain and increase production through acquisitions and exploitation and development projects. For further discussion of our derivative activities, see Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 4, Derivative Activities.

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Cash Flows

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

	Three Months Ended
	March 31, 2012			March 31, 2011
	March 31, 2012			March 31, 2011
Net cash provided by (used in):
Operating activities	$	51,342		$	18,234
Investing activities		(38,410	)		(12,460	)
Financing activities		(9,045	)		(6,139	)

Operating Activities

Our cash flow from operating activities for the three months ended March 31, 2012 was $51.3 million compared to $18.2 million in cash flow from operating activities for the three months ended March 31, 2011. The increase in cash flow from operating activities is mainly attributable to positive changes in working capital for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011 due to the establishment of normalized working capital during the three months ended March 31, 2011 following our initial public offering in December 2010.

Investing Activities

Our cash flow used in investing activities for the three months ended March 31, 2012 was $38.4 million compared to cash flows used in investing activities of $12.5 million for the three months ended March 31, 2011. The increase in cash flow used in investing activities is mainly attributable to increased capital expenditures related to our drilling program on our producing oil and gas assets and a deposit for the Prize Acquisition during the three months ended March 31, 2012 as compared to the three months ended March 31, 2011.

Financing Activities

Our cash flow used in financing activities for the three months ended March 31, 2012 was $9.0 million compared to cash flows used in financing activities of $6.1 million for the three months ended March 31, 2011. The increase in the cash used in financing activities is attributable to distributions to preferred unitholders, offset by borrowings to fund the deposit related to the Prize Acquisition during the three months ended March 31, 2012, which were not present during the three months ended March 31, 2011.

Capital Requirements

We currently expect 2012 spending for the development of our oil and natural gas properties to be approximately $70.0 million and $80.0 million.

We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisitions of oil and natural gas properties in 2012 through a combination of cash, borrowings under our credit facility and the issuance of equity securities.

Contractual Obligations

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

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Off-Balance Sheet Arrangements

As of March 31, 2012, we have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited consolidated financial statements, which have been prepared in accordance with 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 on Form 10-K for the year ended December 31, 2011.

Recent Accounting Pronouncements

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

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

Non-GAAP Financial Measures

We include in this report the non-GAAP financial measures Adjusted EBITDA and Distributable Cash Flow and provide our calculations of Adjusted EBITDA and Distributable Cash Flow and reconciliations to their most directly comparable financial measures calculated and presented in accordance with GAAP.

Adjusted EBITDA

We define Adjusted EBITDA as net income:

•

Plus:

•

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

•

Depreciation, depletion, and amortization;

•

Accretion of asset retirement obligations;

•

Unrealized losses on commodity derivative contracts;

•

Income tax expense;

•

Impairments; and

•

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

•

Less:

•

Income tax benefit;

•

Interest income; and

•

Unrealized gains on commodity derivative contracts.

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We use Adjusted EBITDA to calculate the quarterly administrative services fee our general partner pays to QRM under the services agreement between our general partner and QRM. Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

•

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

•

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

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

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

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

	Three Months Ended
	March 31, 2012			March 31, 2011
Reconciliation of net income to Adjusted EBITDA
Net loss	$	(7,235	)	$	(46,549	)
Plus:
Unrealized loss on commodity derivative contracts		21,769			61,605
Depletion, depreciation and amortization		19,590			18,909
Accretion of asset retirement obligations		843			648
Interest expense		7,472			3,391
Income tax benefit		(31	)		(211	)
General and administrative expense in excess of administrative services fee		6,742			6,005
Adjusted EBITDA	$	49,150		$	43,798

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

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Distributable Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate Distributable Cash Flow in the same manner. The table below summarizes our distributable cash flow for the three months ended March 31, 2012 and 2011.

	Three Months Ended
	March 31, 2012			March 31, 2011
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow:
Net loss	$	(7,235	)	$	(46,549	)
Plus:
Unrealized loss on commodity derivative contracts		21,769			61,605
Depletion, depreciation and amortization		19,590			18,909
Accretion of asset retirement obligations		843			648
Interest expense		7,472			3,391
Income tax benefit		(31	)		(211	)
General and administrative expense in excess of administrative services fee		6,742			6,005
Adjusted EBITDA	$	49,150		$	43,798

Less:
Cash interest expense		(6,088	)		(3,303	)
Estimated maintenance capital expenditures		(12,500	)		(12,500	)
Distributions to preferred unitholders		(3,500	)		-
Management incentive fee earned by GP		(3,155	)		-
Distributable Cash Flow	$	23,907		$	27,995

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Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Derivative Instruments and Hedging Activity

Information about market risk for the first quarter of 2012 did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2011.

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

We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. We do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. Each of the counterparties to our derivative contracts is a lender in our Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Credit Agreement. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 4, Derivative Activities for additional information on our commodity derivatives.

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates into fixed interest rates. We are exposed to market risk on our open contracts, to the extent of changes in LIBOR. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 4, Derivative Activities for additional information on our interest rate swaps.

We account for our derivative activities whereby every derivative instrument is recorded on the balance sheet as either an asset or liability measured at fair value. Refer to Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 4, Derivative Activities for further details.

Item 4.

Controls and Procedures

Material Weaknesses in Internal Control over Financial Reporting.

As previously discussed in Item 9A. “Controls and Procedures” of our 2011 Annual Report on Form 10-K, we reported material weaknesses in certain control activity levels. These material weaknesses continue to exist as of March 31, 2012, 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 Chief Executive Officer, our principal executive officer and Chief Financial Officer, our principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, the "Exchange Act") as of March 31, 2012. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. As a result of the material weaknesses in internal control described in Item 9A. “Controls and Procedures” of our 2011 Annual Report on Form 10-K, the principal executive officer and the principal financial officer concluded that the Partnership's disclosure controls and procedures were ineffective as of March 31, 2012.

Changes in Internal Control over Financial Reporting.

There were no changes in our system of internal control over financial reporting, other than as described below, (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Remediation of Previously Identified Material Weaknesses

During the three months ended March 31, 2012, we continued our efforts to address the material weaknesses in our internal control over financial reporting and the ineffectiveness of our disclosure controls and procedures. Our remediation plan includes the following actions:

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

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

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

Variance analyses have been strengthened to identify material anomalies.

Each of the material weaknesses described in Item 9A. “Controls and Procedures” of our 2011 Annual Report on Form 10-K, could result in a misstatement of mark-to-market expenses for derivatives and long-term derivative assets and liabilities, general and administrative expenses and contributions from the Predecessor, DD&A expense and accumulated DD&A, ad valorem tax payments and ad valorem tax expenses or related disclosures that would result in a material misstatement of our interim consolidated financial statements that would not be prevented or detected. We believe the remediation measures described above will remediate the control deficiencies we have identified and strengthen our internal control over financial reporting. We have begun the testing of the internal controls related to the remediation of these deficiencies, and while we do not have sufficient sample size to conclude on remediation, we have not identified any deficiencies to date. However, 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 2011 Annual Report on Form 10-K or avoid potential future material weaknesses.

Although our remediation efforts are continuing, the material weaknesses previously disclosed in our 2011 Annual Report on Form 10-K will not be considered remediated until new controls over financial reporting are fully designed and operating effectively for an adequate period of time.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

Please see Part 1, Item 3 “- Legal Proceedings” in our Annual Report on Form 10-K. In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We currently have no legal proceedings with a probable adverse outcome. Therefore, we do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Item 1A.

Risk Factors

There have been no material changes to the risk factors described in the Partnership’s Annual Report on Form 10-K, for the year ended December 31, 2011, except as discussed below.

Recently approved final rules regulating air emissions from natural gas production operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. We are currently reviewing this new rule and assessing its potential impacts. Compliance with these requirements could increase our costs of development and production, which costs may be significant.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not Applicable

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 March 19, 2012, by and among QRE Operating, LLC, Prize Petroleum, LLC and Prize Pipeline, LLC (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on March 22, 2012).
3.1		---	Certificate of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.2		---	First Amended and Restated Agreement of Limited Partnership of QR Energy, LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
3.3		---	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, dated as of October 3, 2011 (Incorporated herein by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed October 6, 2011).
3.4		---	Certificate of Formation of QRE GP, LLC (Incorporated by reference to Exhibit 3.4 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.5		---	Amended and Restated Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
10.1		---	Second Amendment to Credit Agreement dated as of March 16, 2012, by and among, QRE Operating, LLC, QR Energy, LP, QRE GP, LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on March 30, 2012).
10.2		---	Third Amendment to Credit Agreement dated April 11, 2012, by and among, QRE Operating LLC, QR Energy, LP, QRE GP, LLC, Wells Fargo Bank, National Association, as Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on April 16, 2012).
31.1	*	---	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
31.2	*	---	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
32.1	**	---	Certification of the Chief Executive Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	**	---	Certification of the Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	**	---	XBRL Instance Document
101.SCH	**	---	XBRL Taxonomy Extension Schema Document
101.CAL	**	---	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	**	---	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	**	---	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	**	---	XBRL Taxonomy Extension Presentation Linkbase Document

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

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

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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: May 10, 2012	By:	/s/ Alan L. Smith
		Alan L. Smith
		Chief Executive Officer and Director

Dated: May 10, 2012	By:	/s/ Cedric W. Burgher
		Cedric W. Burgher
		Chief Financial Officer

QR Energy, LP - FORM 10-Q - May 10, 2012

Attached files

QR Energy, LP Reports