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QR ENERGY, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)


	Three Months Ended
	March 31, 2014		March 31, 2013
Cash flows from operating activities:
Net income (1)	$	(14,396)	$	(8,174)
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization		29,836		30,815
Accretion of asset retirement obligations		2,134		1,732
Recognition of unit-based awards		1,743		1,026
Loss on derivative contracts, net		23,648		16,124
Cash received (paid) on settlement of derivative contracts		(273)		8,165
Loss on deferred Class B unit obligation		5,240		-
Other items		1,643		1,400
Changes in operating assets and liabilities:
Accounts receivable and other assets		(342)		(14,997)
Accounts payable and other liabilities		(7,063)		(2,169)
Net cash provided by operating activities		42,170		33,922
Cash flows from investing activities:
Additions to oil and natural gas properties		(29,833)		(18,507)
Acquisitions		(29,016)		2,277
Proceeds from sale of available-for-sale securities		614		-
Purchases of available-for-sale securities		(189)		-
Net cash used in investing activities		(58,424)		(16,230)
Cash flows from financing activities:
Proceeds from issuance of units		-		80
Management incentive fee to the general partner		(1,399)		-
Distributions to unitholders		(35,422)		(32,284)
Units withheld for employee payroll tax obligation		(25)		(17)
Proceeds from bank borrowings		63,000		-
Deferred financing costs		-		(1,848)
Other		-		121
Net cash provided by (used in) financing activities		26,154		(33,948)
Increase (decrease) in cash		9,900		(16,256)
Cash and cash equivalents at beginning of period		13,360		31,836
Cash and cash equivalents at end of period	$	23,260	$	15,580

(1) Includes net income attributable to noncontrolling interest

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 acquire oil and natural gas assets from our affiliated entity, QA Holdings, LP (the “Predecessor”) and other third party entities to enhance and exploit oil and gas properties. Certain of the Predecessor’s subsidiaries (collectively known as the “Fund”) include Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC.

Our general partner is QRE GP, LLC (“general partner” or “QRE GP”). As a result of the GP Buyout Transaction (described below), QRE GP became a 100% owned subsidiary of the Partnership. We conduct our operations through our 100% owned subsidiary QRE Operating, LLC (“OLLC”). Our 100% owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities. We also have a controlling interest in East Texas Saltwater Disposal Company (“ETSWDC”), a privately held Texas corporation. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil production in the East Texas Oil Field.

On March 2, 2014, we completed a transaction related to our general partner interest pursuant to a Contribution Agreement, by and among the Partnership, the general partner, QR Holdings (QRE), LLC (“QRH”) and QR Energy Holdings, LLC (“QREH” and, together with QRH, the “QR Parties”), the former owners of our general partner, pursuant to which (i) the general partner reclassified its 0.1% general partner interest in the Partnership, formerly represented by 51,036 general partner units, in exchange for a non-economic general partner interest, (ii) the QR Parties contributed 100% of the limited liability company interests of the general partner to the Partnership, and (iii) the partnership agreement was amended, to, among other things, (a) terminate the management incentive fee and provide for the future issuance of up to 11.6 million Class B units, subject to certain tests described in Note 13 – Partners Capital, to the QR Parties and (b) provide for the election of all of the members of the board of directors of the general partner by our limited partners beginning in June 2015 (the “GP Buyout Transaction”).

As of March 31, 2014, our ownership structure comprised a 7.5% limited partner interest in us represented by 6,133,558 Class B units held by our affiliates and former owners of QRE GP, a 29.3% limited partner interest held by the Fund, comprised of common units and all of our preferred units, and a 63.2% limited partner interest held by the public unitholders.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles in the United States (“U.S. GAAP”) for complete annual financial statements. During interim periods, the Partnership follows the accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Annual Report”), filed with the Securities and Exchange Commission (“SEC”). The unaudited consolidated financial statements for the three months ended March 31, 2014 and 2013 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. The unaudited consolidated financial statements include the accounts of the Partnership, its 100% owned subsidiaries, and investments we are deemed to control. All significant intercompany transactions have been eliminated upon consolidation. Prior period amounts have been revised to conform to current period presentation. Operating results for the three months ended March 31, 2014 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2014. 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 2013 Annual Report.

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During the three months ended March 31, 2014, we recorded out-of-period adjustments related to periods from the three months ended December 31, 2012 through the three months ended December 31, 2013 that decreased our income before taxes for the three months ended March 31, 2014 by $1.4 million. These adjustments include a $1.9 million decrease in revenue, a $0.3 million increase in production expenses, and a $0.2 million increase in depletion expense. After evaluating the quantitative and qualitative aspects of the errors, we concluded our previously issued financial statements were not materially misstated and the effect of recognizing these adjustments in the consolidated financial statements for the three months ended March 31, 2014 is not material to our results of operations, financial position, or cash flows.

Accounting Policy Updates

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 2013 Annual Report. The following addition to our policies was made during the three months ended March 31, 2014 to give effect to the GP Buyout Transaction.

Deferred Class B Unit Obligation

Our deferred class B units obligation is classified as a non-current liability and is remeasured each reporting period based on the fair value of the liability. Accordingly, any changes in fair value are included in earnings and reported as a component of Other income, net within our consolidated statement of operations. See Note 11 – Deferred Class B Unit Obligation.

NOTE 3 – ACQUISITIONS

2014 Acquisition

On January 30, 2014, we closed an acquisition of primarily natural gas properties located in East Texas from a private seller for $32.1 million in cash, subject to customary purchase price adjustments, using funds drawn on our revolving credit facility. The acquired properties had estimated proved developed reserves of 3.9 MMBoe as of the date of the acquisition utilizing SEC case pricing.

The following table summarizes the estimated preliminary fair values of the assets acquired and liabilities assumed as of the closing date:


Oil and gas properties	$	35,668
Asset retirement obligation		(772)
Other current liabilities		(2,827)
Net assets acquired		32,069

2013 Acquisition

On August 6, 2013, we closed the acquisition of primarily oil properties located in East Texas (the “2013 East Texas Acquisition”) from a private seller for $107.8 million cash, subject to customary purchase price adjustments using funds drawn on our revolving credit facility. The acquired properties (the “2013 East Texas Properties”) had estimated proved developed reserves of 5.9 MMBoe as of the date of the acquisition utilizing SEC case pricing. The acquisition had an effective date of June 1, 2013. The acquisition costs associated with the 2013 East Texas Acquisition were $0.4 million. In connection with the 2013 East Texas Acquisition, we assumed an estimated environmental liability of $0.5 million. Refer to Note 12 – Commitments and Contingencies for further details.

In connection with the 2013 East Texas Acquisition, we also acquired a 32% interest in ETSWDC giving us control of ETSWDC as we previously owned 24%. As of the closing date of the 2013 East Texas Acquisition, we consolidated ETSWDC into our consolidated financial statements. As a result of consolidation, our previous ownership in ETSWDC was remeasured to fair value on the acquisition date resulting in a gain of $1.3 million recognized in the third quarter of 2013. During the fourth quarter 2013, we acquired an additional 3% from another seller giving us an aggregate 59% ownership interest as of March 31, 2014.

The 2013 East Texas Acquisition qualified as a business combination and was accounted for under the purchase method of accounting. The fair value measurements of the oil and gas properties, the investment in ETSWDC, and asset retirement obligations were measured using valuation techniques and unobservable inputs that convert future cash flows to a single discounted amount.

The following table summarizes the final fair values of the assets acquired and liabilities assumed as of the closing date:

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Oil and gas properties	$	105,751
Investment in ETSWDC		9,576
Asset retirement obligation		(6,069)
Other current liabilities		(1,044)
Net assets acquired	$	108,214

The following table summarizes the final preliminary fair values of the ETSWDC assets and liabilities along with the fair value of the noncontrolling interest to derive our investment in ETSWDC acquired in the 2013 East Texas Acquisition:




Assets acquired and liabilities assumed:
Current assets (1)	$	7,858
Property, plant and equipment, net		13,103
Other long term assets		16,215
Total assets		37,176
Liabilities:
Current liabilities		(1,761)
Asset retirement obligation		(4,607)
Pension and postretirement benefits		(12,039)
Total liabilities		(18,407)
Fair value of saltwater disposal company		18,769
Less: Remeasurement of previously held interest		(3,237)
Less: Fair value of noncontrolling interest in ETSWDC		(5,956)
Fair value of ETSWDC acquired by QR Energy, LP	$	9,576

⁽¹⁾

Includes $3.5 million of cash and cash equivalents.

Pro Forma Information

The following unaudited consolidated income statement information provides actual results for the three months ended March 31, 2014 and pro forma income statement information for the three months ended March 31, 2013, which assumes the 2013 East Texas Acquisition had occurred on January 1, 2012 and the 2014 acquisition had occurred on January 1, 2013. The unaudited pro forma results reflect certain adjustments related to the acquisitions, such as increased depreciation and amortization expense on the fair value of the assets acquired. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisition been completed at the beginning of the periods presented, nor are they indicative of future results of operations.


		Three Months Ended
		(Unaudited)
	March 31, 2014		March 31, 2013
	Pro Forma		Pro Forma
Total revenues	$	123,741	$	121,020
Operating income	$	26,646	$	22,551
Net income (loss) attributable to QR Energy, LP	$	(14,251)	$	(5,136)
Net income per unit:
Common unitholders' (basic and diluted)	$	(2.85)	$	(0.28)

NOTE 4 – INVESTMENTS

Our available for sale securities consist of investments not classified as trading securities or as held-to-maturity. Our investments are classified as “Other assets” on our consolidated balance sheet.

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As of March 31, 2014, we had the following available-for-sale investments outstanding:


	Cost		Gross		Gross
	Basis		Unrealized Gains		Unrealized Losses		Fair Value

Available-for-sale securities:
Equities	$	3,632	$	373	$	44	$	3,961
Mutual funds		10,914		430		8		11,336
Exchange traded funds		2,924		267		-		3,191
Total for available-for-sale securities	$	17,470	$	1,070	$	52	$	18,488

During the three months ended March 31, 2014 we received $0.6 million in proceeds from the sale of available-for-sale securities with a realized loss of less than $0.1 million.

We evaluate securities for other than temporary impairment on a quarterly basis and more frequently when economic or market concerns warrant such an evaluation. The unrealized losses above have been outstanding for less than nine months. We have evaluated the unrealized losses above and have determined that these losses do not represent an other than temporary impairment.

NOTE 5 – FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

Available for Sale Securities — The fair value of the available-for-sale securities are estimated using actual trade data, broker/dealer quotes, and other similar data, which are obtained from quoted market prices, independent pricing vendors, or other sources. We validate the data provided by independent pricing services to make assessments and determinations as to the ultimate valuation of its investment portfolio by comparing such pricing against other third party pricing data.

Deferred Class B Unit Obligation—The Deferred Class B Unit Obligation represents consideration for the GP Buyout. The fair value of the deferred Class B unit obligation is estimated using a combination of quoted market prices and the probability of achieving operating performance related to (a) the distribution rate, (b) Distribution Coverage Ratio (as defined in our Partnership Agreement), and (c) Total Debt to EBITDAX (as defined in our Partnership Agreement )(collectively “the Class B Criteria”). The Class B Criteria represent significant unobservable inputs. The valuation methodology assumes the operating performance will be achieved within 6 years from the GP Buyout. If the Class B Criteria is not satisfactorily met within 6 years of the GP Buyout, all or a portion

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of the obligation may not be redeemable. If the Class B Criteria is met, we estimate that 11.6 million Class B units will be issued within 6 years and will then be valued based upon quoted market prices.

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, 2014 and December 31, 2013. All fair values reflected below have been adjusted for nonperformance risk.



As of March 31, 2014		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	68,244	$	-	$	68,244	$	-
Assets from interest rate derivative instruments		144		-		144		-
Total assets from derivative instruments		68,388		-		68,388		-
Available for sale securities:
Equities		3,961		3,961		-		-
Mutual funds		11,336		11,336		-		-
Exchange traded funds		3,191		3,191		-		-
Total available for sale securities		18,488		18,488		-		-
	$	86,876	$	18,488	$	68,388	$	-

Liabilities from commodity derivative instruments	$	10,093	$	-	$	10,093	$	-
Liabilities from interest rate derivative instruments		9,538		-		9,538		-
Deferred Class B Unit Obligation		147,017		-		-		147,017
	$	166,648	$	-	$	19,631	$	147,017

As of December 31, 2013		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	89,616	$	-	$	89,616	$	-
Available for sale securities:
Equities		3,967		3,967		-		-
Mutual funds		11,639		11,639		-		-
Exchange traded funds		3,140		3,140		-		-
Total available for sale securities		18,746		18,746		-		-
	$	108,362	$	18,746	$	89,616	$	-

Liabilities from commodity derivative instruments	$	7,093	$	-	$	7,093	$	-
Liabilities from interest rate derivative instruments		10,391		-		10,391		-
	$	17,484	$	-	$	17,484	$	-

The table below presents a reconciliation of the liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2014. There were no Level 3 instruments for the three months ended March 31, 2013. The Level 3 instruments presented in the table consists of the entitlement our former general partner owners have to receive up to an aggregate of 11.6 million Class B units.


		Three Months Ended
		March 31, 2014
Balance at beginning of period	$	-
Recognition of deferred Class B unit obligation		141,777
Changes in fair value		5,240
Transfers in and (out) of Level 3		-
Balance at end of period	$	147,017
Loss on deferred Class B unit obligation attributable to the change in fair value still held at the end of the period	$	5,240

The fair value of the Level 3 deferred Class B unit obligation has been determined using available market information and commonly accepted valuation methodologies. Specifically, we valued our key non-observable performance inputs using a Monte-Carlo valuation model. The key assumptions of the valuation model consist of performance criteria as described in Note 13 – Partners’ Capital and include EBITDA volatility of 20% and equity volatility at 30%. Considerable judgment is required in interpreting the market data to develop the estimate of fair value. Accordingly, our estimates are not necessarily indicative of the amounts that we, or holders of the obligation, could realize in a current market exchange. The use of different assumptions and/or estimation methodologies could

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have a material effect on the estimated fair values. These amounts have not been revalued since the period indicated above, and current estimates of fair value could differ significantly from the amounts presented.

Fair Value of Other Financial Instruments

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

Revolving Credit Facility — The fair value of our revolving credit facility depends primarily on the current active market LIBOR. The carrying value of our revolving credit facility as of March 31, 2014 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.

Derivative Premiums – The fair value of the deferred premiums on our commodity derivatives is based on the current active market LIBOR. The carrying value of the premiums as of March 31, 2014 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy. Refer to Note 6 – Derivative Activities for further information on the derivative premiums.

Senior Notes – The fair value of our senior notes is measured based on inputs from quoted, unadjusted prices from over-the-counter markets for debt instruments. If the senior notes had been measured at fair value, we would classify them as Level 1 under the fair value hierarchy. The fair value of our senior notes as of March 31, 2014 was $326.4 million.

There have been no transfers between levels within the fair value measurement hierarchy during the three months ended March 31, 2014.

NOTE 6 – DERIVATIVE ACTIVITIES

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

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

Commodity Derivatives

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

During the three months ended March 31, 2014, we did not enter into any new oil swap and basis swap contracts. All existing contracts were entered into with the counterparties under our revolving credit facility.

The deferred premiums associated with certain of our oil and natural gas derivative instruments were $0.1 million and $5.0 million and are classified as accrued and other liabilities and other non-current liabilities on the consolidated balance sheet as of March 31, 2014. The deferred premiums associated with certain of our oil and natural gas derivative instruments were zero and $5.0 million and are classified as accrued and other liabilities and other non-current liabilities on the consolidated balance sheet as of December 31, 2013. These deferred premiums will be paid to the counterparty with each monthly settlement (January 2015 – December 2017) and will be recognized as an adjustment of gain (loss) on commodity derivative contracts, net.

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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, 2014, the notional volumes of our commodity derivative contracts were:



Commodity	Index		April 1 - Dec 31, 2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		6,711		7,356		6,293		5,547
Average price ($/Bbls)		$	95.30	$	93.74	$	90.03	$	86.23
Hedged Volume (Bbls/d)	LLS		3,000		-		-		-
Average price ($/Bbls)		$	99.62		-		-		-
Basis
Hedged Volume (Bbls/d)	WTS/WTI		2,400		-		-		-
Average price ($/Bbls)		$	(2.10)		-		-		-
Collars
Hedged Volume (Bbls/d)	WTI		425		1,025		1,500		-
Average floor price ($/Bbls)		$	90.00	$	90.00	$	80.00		-
Average ceiling price ($/Bbls)		$	106.50	$	110.00	$	102.00		-

Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		26,466		7,191		11,350		10,445
Average price ($/MMBtu)		$	6.12	$	5.34	$	4.27	$	4.47
Basis Swaps (1)
Hedged Volume (MMBtu/d)	Henry Hub		17,055		14,400		-		-
Average price ($/MMBtu)		$	(0.19)	$	(0.19)		-		-
Collars
Hedged Volume (MMBtu/d)	Henry Hub		4,955		18,000		630		595
Average floor price ($/MMBtu)		$	5.74	$	5.00	$	4.00	$	4.00
Average ceiling price ($/MMBtu)		$	7.51	$	7.48	$	5.55	$	6.15
Puts
Hedged Volume (MMBtu/d)	Henry Hub		-		420		11,350		10,445
Average price ($/MMBtu)			-	$	4.00	$	4.00	$	4.00

⁽¹⁾

Our natural gas basis swaps are used to hedge the differential between Henry Hub and various price points.

Interest Rate Derivatives

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

During the three months ended March 31, 2014, we did not enter into any new interest rate swaps. All existing contracts were entered into with various financial institutions.

Financial Statement Presentation of Derivatives

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



	March 31, 2014				December 31, 2013
		Asset		Liability		Asset		Liability
		Derivatives		Derivatives		Derivatives		Derivatives
Commodity contracts	$	68,244	$	10,093	$	89,616	$	7,093
Interest rate contracts		144		9,538		-		10,391
	$	68,388	$	19,631	$	89,616	$	17,484

Commodity
Current	$	19,603	$	8,130	$	27,485	$	5,651
Noncurrent		48,641		1,963		62,131		1,442
	$	68,244	$	10,093	$	89,616	$	7,093
Interest
Current	$	-	$	5,744	$	-	$	5,582
Noncurrent		144		3,794		-		4,809
	$	144	$	9,538	$	-	$	10,391

Total Derivatives
Current	$	19,603	$	13,874	$	27,485	$	11,233
Noncurrent		48,785		5,757		62,131		6,251
	$	68,388	$	19,631	$	89,616	$	17,484

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The following table presents our derivatives on a net basis as of the dates indicated:


	March 31, 2014				December 31, 2013
		Asset		Liability		Asset		Liability
		Derivatives		Derivatives		Derivatives		Derivatives

Gross derivatives	$	68,388	$	19,631	$	89,616	$	17,484
Netting		(3,509)		(3,509)		(2,960)		(2,960)
Net derivatives	$	64,879	$	16,122	$	86,656	$	14,524

The following table presents the impact of derivatives and their location within our consolidated statements of operations for the three months ended March 31, 2014 and 2013:



	Three Months Ended
		March 31, 2014		March 31, 2013
Total gains (losses):
Commodity contracts (1)	$	(23,165)	$	(16,006)
Interest rate swaps (2)		(483)		(118)
Total	$	(23,648)	$	(16,124)

⁽¹⁾

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

⁽²⁾

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

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

We record the estimated asset retirement obligation (“ARO”) as a liability on our consolidated balance sheet and capitalize the cost in the “Oil and natural gas properties, using the full cost method of accounting” or “Other property, plant and equipment” balance sheet captions during the period in which the obligation is incurred. We record the accretion of our ARO liabilities in “Accretion of asset retirement obligations” in our consolidated statements of operations. Payments to settle asset retirement obligations occur over the lives of the oil and natural gas properties and other property, plant and equipment.

Changes in our asset retirement obligations for the three months ended March 31, 2014 are presented in the following table:



		Three Months Ended
		March 31, 2014
Beginning of period	$	155,321
Assumed in acquisition		772
Revisions to previous estimates		334
Liabilities incurred		113
Liabilities settled		(404)
Accretion expense		2,134
End of period	$	158,270
Less: Current portion of asset retirement obligations		(4,461)
Asset retirement obligations - non-current	$	153,809

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NOTE 8 – ACCRUED AND OTHER LIABILITIES

As of March 31, 2014 and December 31, 2013, accrued and other liabilities consisted of the following:



		March 31, 2014		December 31, 2013
Accrued lease operating expenses	$	19,843	$	20,297
Accrued capital spending		19,530		16,316
Distributions payable		14,144		14,155
Gas imbalance liability		6,464		6,214
Accrued production and other taxes		5,946		6,270
Senior notes accrued interest		4,625		11,563
Accrued transaction costs		3,631		203
Other		4,783		4,027
Total accrued and other liabilities	$	78,966	$	79,045

NOTE 9 – PENSIONS AND POSTRETIREMENT BENEFITS

ETSWDC sponsors a non-contributory defined benefit pension plan and a contributory postretirement benefit plan covering substantially all its employees.

The components of net periodic benefit costs are reflected in our consolidated statements of operations in the “Disposal and related operating expense” caption as follows:



	Three Months Ended		Three Months Ended
	March 31, 2014		March 31, 2013
Qualified Pension Plan
Interest cost	$	257,364	$	-
Service cost		61,521		-
Expected return on plan assets		(337,278)		-
Net periodic pension cost (income)	$	(18,393)	$	-

Postretirement Benefits
Interest cost	$	43,110	$	-
Service cost		8,526		-
Expected return on plan assets		(24,423)		-
Amortization of (gain)/loss		(68,265)		-
Total postretirement benefit cost (income)	$	(41,052)	$	-

NOTE 10 – LONG-TERM DEBT

As of March 31, 2014 and December 31, 2013, consolidated debt obligations consisted of the following:


		March 31, 2014		December 31, 2013
Senior secured revolving credit facility	$	678,000	$	615,000
9.25% Senior Notes (1)		296,723		296,593
Total long-term debt	$	974,723	$	911,593

Letters of credit (2)	$	23,488	$	23,488

⁽¹⁾

The amount is net of unamortized discount of $3.3 million and $3.4 million as of March 31, 2014 and December 31, 2013, respectively.

⁽²⁾

These letters of credit relate to a reclamation deposit requirement of $23.4 million and others totaling $0.1 million. Refer to Note 12 – Commitments and Contingencies for details on the reclamation deposit.

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”).

Effective March 2, 2014, we entered into the sixth amendment to the Credit Agreement, which permitted the GP Buyout Transaction and provides for the exclusion of QRE GP as a guarantor of our credit facility.

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As of March 31, 2014, we had $678.0 million of borrowings outstanding with borrowing availability of $248.5 million ($950.0 million of borrowing base less $678.0 million of outstanding borrowing and $23.5 million of letters of credit) under the Credit Agreement.

As of March 31, 2014, the Credit Agreement provided for a $1.5 billion revolving credit facility maturing on April 20, 2017, with a borrowing base of $950.0 million. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ pricing assumptions, and other various factors unique to each member bank. The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. ETSWDC and QRE GP are not subsidiary guarantors under our Credit Agreement. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum.

The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and also requires us to provide audited financial statements within 90 days of year end and quarterly unaudited financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of March 31, 2014, we were in compliance with all of the Credit Agreement covenants.

On April 21, 2014, we entered into the seventh amendment to the Credit Agreement, which reduced the borrowing base from $950 million to $900 million.

As of May 5, 2014 we had $693 million of borrowings outstanding with borrowing availability of $183.5 million ($900 million of borrowing base less $693 million of outstanding borrowing and $23.5 million of outstanding letters of credit) under the Credit Agreement.

9.25% Senior Notes

On July 30, 2012, we and our 100% owned subsidiary QRE FC, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of 9.25% Senior Notes, due 2020 (the “Senior Notes”). The Senior Notes were issued at 98.62% of par with interest payments to be made on February 1 and August 1 each year beginning in 2013. In 2012, we filed and completed a registration statement with the SEC to allow the holders of the Senior Notes to exchange for registered Senior Notes that have substantially identical terms as the Senior Notes. We have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Our and QRE FC’s obligations under the Senior Notes are guaranteed by OLLC. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted

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Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor’s, other, debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Note 20 – Subsidiary Guarantors for further details of our guarantors.

The indenture governing the Senior Notes (the “Indenture”) restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale-leaseback transactions; (ii) pay distributions on, or repurchase, equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants. The Indenture also includes customary events of default. As of March 31, 2014, we were in compliance with all financial and other covenants of the Senior Notes.

NOTE 11 – DEFERRED CLASS B UNIT OBLIGATION

In connection with the GP Buyout Transaction, the former owners of the GP are entitled to receive up to 11.6 million Class B units, subject to certain tests. See Note 13 – Partners’ Capital.

As of March 31, 2014, the fair value of this obligation, which can only be settled through the issuance of Class B units, amounted to $147 million. During the period from March 2, 2014 through March 31, 2014, we recognized $5.2 million in losses attributable to the fair value change in the deferred Class B unit obligation.

NOTE 12 – COMMITMENTS AND CONTINGENCIES

Property Reclamation Deposit

As of March 31, 2014 and December 31, 2013, $10.7 million is recorded in other assets on the consolidated balance sheets related a property reclamation deposit with ExxonMobil Corporation (the “Seller”). We are required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to us until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, we have the right to request a refund of a portion or all of the property reclamation deposit. Granting of the request is at the Seller’s sole discretion. In addition to the cash deposit, a letter of credit of $23.4 million is required in favor of the Seller.

NPI Obligation

As a part of our acquisition of certain oil producing properties from the Fund in December 2012, we assumed a net profit interest (“NPI”) related to the Jay field. Under the arrangement, the NPI is payable after: (i) funds are withheld, to the extent allowable each month under the arrangement, to pay for the NPI holder’s share of future development costs and abandonment obligations, and (ii) we are reimbursed for the NPI holder’s share of excess historical productions costs. Once the NPI holder’s share of the excess historical costs is reimbursed, the NPI will be payable monthly to extent the NPI for that month exceeds amount withheld for that month for future development costs and abandonment obligations. The NPI holder’s share of excess historical production costs amounted to $1.3 million and $2.9 million as of March 31, 3014 and December 31, 2013, respectively. In addition, we will retain the NPI holder’s shares of future development costs and abandonment obligations, subject to future production, production costs, and capital spending level, which will be paid using the funds withheld. The NPI holder’s share along with our share of the abandonment costs is reflected in our asset retirement obligations as of March 31, 2014 and December 31, 2013.

Under the arrangement, the Partnership is required to deposit into a separate account the funds withheld from the NPI holder for their portion of the future development costs and abandonment obligations. The account for these funds in the amount approximately $18 million will be established in the second quarter of 2014.

Lease Guarantees

The Fund has entered into various lease contracts that can routinely extend beyond five years which list the Partnership as a guarantor. In December 2012, we were named guarantor for QRM’s office lease in Houston, Texas with an approximate value of $26.8 million that terminates in 2022.

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Legal Proceedings

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

Environmental Contingencies

As of March 31, 2014 and December 31, 2013, we had approximately $2.2 million and $2.3 million, respectively, in environmental liabilities related to the 2013 East Texas Acquisition and the the acquisition of primarily oil properties, almost all of which are in the ArkLaTex area, from Prize Petroleum, LLC and Prize Petroleum Pipeline, LLC (the “Prize Acquisition”). This is management’s best estimate of the costs for remediation and restoration with respect to these environmental matters, although the ultimate cost could vary. The environmental liability is recorded in the other liabilities caption on the consolidated balance sheet. Inherent uncertainties exist in these estimates primarily due to unknown conditions, changing governmental regulation and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration.

NOTE 13 — PARTNERS’ CAPITAL

Units Outstanding

The table below details the units outstanding as of March 31, 2014 and December 31, 2013, and the changes in outstanding units for the three months ended March 31, 2014. As of March 31, 2014, the Fund owned all preferred units and all affiliated common units.


	Class C Convertible Preferred Units	General Partner	Class B Units	Public Common	Affiliated Common
Balance - December 31, 2013	16,666,667	51,036	6,133,558	51,483,263	7,145,866
Buyout of general partner	-	(51,036)	-	-	-
Vested units awarded under our Long-Term Incentive
Performance Plan	-	-	-	7,272	-
Reduction in units to cover individuals' tax withholdings	-	-	-	(1,339)	-
Balance - March 31, 2014	16,666,667	-	6,133,558	51,489,196	7,145,866

As a result of the GP Buyout Transaction, the limited liability company interest of the general partner was contributed to the Partnership.

On March 3, 2014, we filed a prospectus supplement establishing an at-the-market equity program under which we may sell common units with an aggregate offering price up to $100 million, from time to time, until the expiration of our shelf filing in June 2015.

On January 14, 2014, we filed an automatic registration statement on Form S-3 with the SEC to register our common units, preferred units and our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC.

Class B Units

As of March 31, 2014, the former owners of our general partner own a 7.5% limited partnership interest in us, represented by 6,133,558 Class B units. The Class B units are immediately convertible into common units at the election of the former owners of our general partner. Class B units have all the rights of common units except for the right to vote on matters requiring specific approval by common unitholders, and are allocated income in an amount that is equal to their distributions.

Pursuant to the GP Buyout Transaction completed on March 2, 2014, the former owners of our general partner are entitled to receive up to an aggregate of 11.6 million Class B units in up to four annual installments during the next six calendar years, beginning with respect to the year ending December 31, 2014. The former owners are entitled to receive an annual installment of such units with respect to any calendar year in which we pay a

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distribution of $0.4744 per unit with respect to each quarter, achieved a Distribution Coverage Ratio (as defined in our Partnership Agreement) for the year of at least 1.0 and achieve a Total Debt to EBITDAX (as defined in our Partnership Agreement) of no greater than 4.0 for each quarter during such year, unless any excess has been approved by the conflicts committee of our general partner. The Class B units have the same rights, preferences and privileges of our common units and are entitled to the same cash distributions per unit as our common units, except in liquidation where distributions are made in accordance with the respective capital accounts of the units and are convertible into an equal number of common units at the election of the holder. These Class B units may be issued as incentives without any corresponding increase in the cash distributions we pay to our unitholders, and any such Class B units issued to the former owners of our general partner will not be subject to forfeiture should we fail to meet the issuance criteria in future periods.

On February 22, 2013, our general partner elected to convert 80% of its fourth quarter 2012 management incentive fee and, on March 4, 2013, received 6,133,558 Class B units which were issued and outstanding upon conversion. As a result, in the first quarter 2013 our general partner received a reduced fourth quarter management incentive fee of $0.7 million and a distribution of $3.0 million on the Class B units related to the fourth quarter 2012.

Allocation of Net Income (Loss)

Net income (loss) is reduced by noncontrolling interest and is then allocated to the preferred and Class B unitholders to the extent distributions are made or accrued to them during the period and, for 2013, to QRE GP to the extent of the management incentive fee. The remaining income is allocated between QRE GP and the common unitholders in proportion to their pro rata ownership during the period. Subsequent to the GP Buyout Transaction on March 2, 2014, net income (loss) is not allocated to QRE GP.

Cash Distributions

Our partnership agreement, as amended, requires that within 45 days after the end of each quarter, or at the discretion of the general partner, in three equal installments within 15, 45, and 75 days following 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 our Board of Directors.

The following sets forth the distributions that have been declared and paid or are payable:


										Limited Partners
												Affiliated
For the period ended		Distributions to Preferred Unitholders		Distributions per Preferred Unit		General Partner		Class B		Public Common		Common		Total Distributions to Other Unitholders		Distributions per other units

December 31, 2013 (1)	$	3,500	$	0.21	$	-	$	-	$	-	$	-	$	-	$	-
December 31, 2013 (2)		-		-		8		987		8,489		1,161		10,645		0.1625
December 31, 2013 (3)		-		-		8		988		8,489		1,161		10,646		0.1625
December 31, 2013 (4)		-		-		8		988		8,484		1,161		10,641		0.1625
March 31, 2014 (5)		-		-		-		978		8,485		1,161		10,624		0.1625
March 31, 2014 (6)		-		-		-		997		8,385		1,161		10,543		0.1625

⁽¹⁾

Distributions were made within 45 days after the end of each quarter.

⁽²⁾

In December 2013, the Board of Directors approved the first monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in January 2014 to the unitholders of record as of January 13, 2014. This distribution was recorded in the fourth quarter 2013.

⁽³⁾

In January 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in February 2014 to the unitholders of record as of February 10, 2014.

⁽⁴⁾

In February 2014, the Board of Directors approved the third monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in March 2014 to the unitholders of record as of March 10, 2014.

⁽⁵⁾

In March 2014, the Board of Directors approved the first monthly distribution of $0.1625 per unit with respect to the first quarter of 2014 which was paid in April 2014 to the unitholders of record as of April 9, 2014.

⁽⁶⁾

In April 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the first quarter of 2014 which was paid in May 2014 to the unitholders of record as of May 8, 2014.

On April 24, 2014, the board of directors declared a $0.1625 per unit cash distribution for the second quarter 2014 which is payable on May 14, 2014 to unitholders of record at the close of business on May 8, 2014.

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NOTE 14 – NET INCOME (LOSS) PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income per limited partner unit for the three months ended March 31, 2014 and 2013:



	Three Months Ended
	March 31, 2014		March 31, 2013
Net income (loss)	$	(14,396)	$	(8,174)
Net income attributable to noncontrolling interest		(214)		-
Net income attributable to QR Energy, LP		(14,610)		(8,174)
Distribution on Class C convertible preferred units		(3,500)		(3,500)
Amortization of preferred unit discount		(3,988)		(3,829)
Distribution on Class B units		(2,962)		(2,990)
Net income (loss) available to other unitholders		(25,060)		(18,493)
Less: general partners' interest in net income		142,579		734
Limited partners' interest in net income (loss)	$	(167,639)	$	(19,227)
Common unitholders' interest in net income (loss)	$	(167,639)	$	(19,227)
Net income (loss) attributable to QR Energy, LP per limited partner unit:
Common unitholders' (basic and diluted)	$	(2.86)	$	(0.33)
Weighted average number of limited partner units outstanding (in thousands) (1)
Common units (basic and diluted)		58,631		58,445

⁽¹⁾

For the three months ended March 31, 2014 and 2013, we had weighted average preferred units outstanding of 16,666,667. The preferred and Class B units are contingently convertible into common units and could potentially dilute earnings per unit in the future. The preferred and Class B units have not been included in the diluted earnings per unit calculation for the three months ended March 31, 2014 and 2013, as they were anti-dilutive for the periods. For the three months ended March 31, 2014, we had 11.6 million Deferred Class B units which were also not included in the diluted earnings per unit calculation as they were anti-dilutive for the period.

Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the limited partner, after deducting QRE GP’s interest in net income (loss) through the date of the GP Buyout Transaction, by the weighted average number of limited partner units outstanding during the three months ended March 31, 2014 and 2013.

NOTE 15 – ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

Changes in accumulated other comprehensive income / (loss) by component, net of tax, were as follows:



		Gains/(loss) on
		Available-For-Sale		Postretirement
		Securities		Benefits		Total
Accumulated comprehensive income as of December 31, 2013	$	613	$	4,061	$	4,674
Other comprehensive income before reclassifications		73		-		73
Amounts reclassified from accumulated other comprehensive income (1)		(14)		(44)		(58)
Net current period other comprehensive income		59		(44)		15
Accumulated comprehensive income as of March 31, 2014	$	672	$	4,017	$	4,689

Accumulated comprehensive income attributable to non-controlling interest		298		1,638		1,936
Accumulated comprehensive income attributable to QR Energy, LP	$	374	$	2,379	$	2,753

⁽¹⁾

Amounts were reclassified from accumulated other comprehensive income / (loss) into “Other income (expense), net” in the Consolidated Statement of Operations.

NOTE 16 – UNIT-BASED COMPENSATION

The QRE GP, LLC Long-Term Incentive Plan (the “Plan”) was established for employees, officers, consultants and directors of the Partnership and its affiliates, including QRM, who perform services for us. The Plan consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the Plan is to provide additional incentive compensation to such individuals providing services to us and to align the economic interests of such individuals 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.

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On March 10, 2014, we held a special meeting our common unitholders. At the meeting our common unitholders approved the First Amendment to the QRE GP, LLC Long-Term Incentive Plan (the “Amended LTIP”). The Amended LTIP increases the number of common units available for delivery with respect to awards under the Plan so that, an additional 3 million common units are available for delivery with respect to awards under the Amended LTIP.

Restricted Units

Periodically we issue restricted units with a service condition (“Restricted Units”) and restricted units with a market condition (“Performance Units”). The fair value of the Restricted Units, based on the closing price of our common units at the grant date, is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the Performance Units, based on a Monte Carlo model with assumptions based on market conditions, is amortized to compensation expense on a straight-line basis over the vesting period of the award.

On April 22, 2013, we granted approximately 455,000 Restricted Unit awards and approximately 149,000 Performance Unit awards to employees of QRM and 20,000 unit awards to independent directors of the Partnership.

Service Restricted Units

For the three months ended March 31, 2014 and 2013, we recognized compensation expense related to the outstanding Restricted Units of $1.5 million and $0.9 million.

Performance Restricted Units.

The Performance Units will be earned over a three year period based on the Partnership’s performance relative to its peers in accordance with the Plan. The final units to be issued will range from 0 – 225% of the initial units granted. For the three months ended March 31, 2014 and 2013, we recognized $0.2 million and $0.1 million of compensation expense related to the Performance Units.

The following table summarizes the activity of our Restricted Units and Performance Units for March 31, 2014:


		Weighted			Weighted
		Average			Average
	Number of	Grant-Date		Number of	Grant-Date
	Service Restricted units	Fair Value		Performance units	Fair Value
Unvested units, December 31, 2013	754,822	$	18.22	267,489	$	10.17
Granted	-		-	-		-
Forfeited	(15,922)		18.19	-		-
Vested	(7,272)		21.58	-		-
Unvested units, March 31, 2014	731,628	$	18.18	267,489	$	10.17

NOTE 17 – INCOME TAXES

The Company is a limited partnership for federal and state income tax purposes, with the exception of the State of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. In addition, the Company’s controlling interest in ETSWDC is subject to federal income tax. The Company recognized income tax expense for the three months ended March 31, 2014 and 2013 of less than $0.1 million.

The IRS is currently auditing the Company’s partnership federal income tax return for the year ended December 31, 2011. We are fully cooperating with the IRS in the audit process. Although no assurance can be given, we do not anticipate any change in prior period taxable income.

NOTE 18 – RELATED PARTY TRANSACTIONS

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

Through March 2, 2014, affiliates of the Fund owned 100% of QRE GP. As of March 31, 2014, the Fund owned an aggregate 29.3% limited partner interest in us represented by all of our Class C preferred units and 7,145,866 common units. In addition, former owners of QRE GP owned a 7.5% limited partner interest in us, represented by 6,133,558 Class B units.

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Contracts with the Former Owners of QRE GP and its Affiliates

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

Services Agreement

QRM provides management and operational services for us and the Fund. In accordance with the Services Agreement, QRM is entitled to the reimbursement of general and administrative expenses based on the allocation of charges to us based on the estimated use of such services between us and the Fund. The reimbursement includes direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If our sponsor raises additional funds in the future, the quarterly allocated costs will be further divided to include the sponsor’s additional funds as well. These fees will be included in general and administrative expenses in our consolidated statement of operations. QRM will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement. Management believes this allocation methodology is a reasonable method of allocating general and administrative expenses between us and the Fund and provides for a reasonably accurate depiction of what our general and administrative expenses would be on a stand-alone basis without affiliations with the Fund or QRM. For the three months ended March 31, 2014 and 2013, we were charged $7.6 million and $8.4 million in allocated general and administrative expenses from 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 receivable balances during the three months ended March 31, 2014 are included below:



Net affiliate receivable as of December 31, 2013	$	3,915
Revenues and other increases		111,480
Expenditures		(81,180)
Settlements from the Fund		(30,838)
Net affiliate receivable as of March 31, 2014	$	3,377

Management Incentive Fee

Through March 2, 2014, 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 was entitled to a quarterly management incentive fee subject to an adjusted operating surplus threshold as defined in the partnership agreement (“Adjusted Operating Surplus”). Pursuant to the GP Buyout Transaction completed on March 2, 2014 (see Note 1 – Organization and Operations), the management incentive fee was terminated effective for periods subsequent to December 31, 2013.

For the three months ended March 31, 2014, $1.4 was recognized for the management incentive fee related to the fourth quarter 2013. For the three months ended March 31, 2013, no management incentive fee was earned related to the fourth quarter 2012 due to the adjusted operating surplus limitation.

On February 22, 2013, in accordance with our partnership agreement, our general partner elected to convert 80% of its fourth quarter 2012 management incentive fee and on March 4, 2013, received 6,133,558 Class B units which were issued and outstanding upon conversion. In exchange for the issuance of Class B units, management incentive fees payable in the future will, if earned, be reduced to the extent of this and any future conversions. As a result, our general partner received a reduced fourth quarter management incentive fee of $0.7 million and a distribution of $3.0 million on the Class B units related to the fourth quarter 2012.

Long–Term Incentive Plan

The Plan provides compensation for employees, officers, consultants and directors of the Partnership and its affiliates, including QRM, who perform services for us. As of March 31, 2014 and December 31, 2013, 999,117 and 1,022,311 restricted units were outstanding under the Amended LTIP and Plan, respectively. For additional discussion regarding the Plan see Note 16 – Unit-Based Compensation.

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Distributions of Available Cash to Former Owners of QRE GP and Affiliates

We generally make cash distributions to our common and affiliated common unitholders pro rata, including former owners of QRE GP and its affiliates. Refer to Note 13 – Partners’ Capital for details on the distributions.

Our Relationship with Bank of America

Don Powell, one of our independent directors, served as an independent director of Bank of America (“BOA”) through May 2013 and did not seek re-election. BOA is a lender under our Credit Agreement.

NOTE 19 – SUPPLEMENTAL CASH FLOW INFORMATION

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



		Three Months Ended
		March 31, 2014		March 31, 2013
Supplemental Cash Flow Information
Cash paid during the period for interest	$	19,292	$	18,091
Non-cash Investing and Financing Activities
Change in accrued capital expenditures		3,214		889
Amortization of increasing rate distributions(1)		3,988		3,829

⁽¹⁾

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

NOTE 20 – SUBSIDIARY GUARANTORS

The Senior Notes, issued on July 30, 2012 by the Partnership and QRE FC (the “Subsidiary Co-Issuer”), are guaranteed by OLLC, a 100% owned subsidiary of the Partnership (the “Guarantor”), and may be guaranteed by certain other future subsidiaries. The Guarantor is 100% owned by the Partnership and its guarantee of the Senior Notes is full and unconditional. The Partnership has no assets or operations independent of its subsidiaries and there are no significant restrictions upon the ability of the Guarantor to distribute funds to the Partnership. The guarantee constitutes a joint and several obligation with any additional future guarantees. The Partnership’s other subsidiaries are ETSWDC and QRE GP, which was contributed to the Partnership upon the completion of the GP Buyout Transaction, and do not guarantee the Senior Notes (the “Non-Guarantor”). Refer to Note 10 – Long-Term Debt for details on the conditions under which guarantees of the Senior Notes may be released. ETSWDC is a non-minor subsidiary and we are providing condensed consolidated financial statements prospectively in accordance with SEC regulations.

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The following condensed consolidated financial information is presented in accordance with Rule 3-10 of the Securities and Exchange Commission’s Regulation S-X, and uses the same accounting policies used to prepare the financial information located elsewhere in our consolidated financial statements and related footnotes.



Condensed Consolidating Balance Sheets
	March 31, 2014
		Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations		Consolidated
Assets
Current assets
Cash	$	73	$	-	$	21,117	$	2,070	$	-	$	23,260
Accounts receivable		9		-		55,092		3,594		(1,028)		57,667
Due from affiliates		219,413		-		-		-		(216,036)		3,377
Derivative instruments		-		-		19,603		-		-		19,603
Prepaid and other current assets		-		-		1,567		83		-		1,650
Total current assets		219,495		-		97,379		5,747		(217,064)		105,557
Noncurrent assets
Oil and natural gas properties and other property and equipment, net		-		-		1,630,262		14,595		-		1,644,857
Derivative instruments		-		-		48,785		-		-		48,785
Investment in subsidiaries		675,968		-		16,800		-		(692,768)		-
Other assets		4,485		-		16,142		19,665		-		40,292
Total noncurrent assets		680,453		-		1,711,989		34,260		(692,768)		1,733,934
Total assets		899,948		-		1,809,368		40,007		(909,832)		1,839,491

Liabilities and Partners' Capital
Current liabilities
Current portions of asset retirement obligations	$	-	$	-	$	4,461	$	-	$	-	$	4,461
Due to affiliates		-		-		216,036		-		(216,036)		-
Derivative instruments		-		-		13,874		-		-		13,874
Accrued and other liabilities		18,769		-		59,511		1,714		(1,028)		78,966
Total current liabilities		18,769		-		293,882		1,714		(217,064)		97,301
Noncurrent liabilities
Long-term debt		296,723		-		678,000		-		-		974,723
Deferred Class B unit obligation		147,017										147,017
Derivative instruments		-		-		5,757		-		-		5,757
Asset retirement obligations		-		-		148,618		5,191		-		153,809
Other liabilities		-		-		7,143		7,533		-		14,676
Total noncurrent liabilities		443,740		-		839,518		12,724		-		1,295,982
Partners' capital
QR Energy, LP partners' capital		437,439		-		675,968		25,569		(701,537)		437,439
Noncontrolling interest		-		-		-		-		8,769		8,769
Total partners' capital		437,439		-		675,968		25,569		(692,768)		446,208
Total liabilities and partners' capital	$	899,948	$	-	$	1,809,368	$	40,007	$	(909,832)	$	1,839,491

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Condensed Consolidating Balance Sheets
	December 31, 2013
		Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations		Consolidated
Assets
Current assets
Cash	$	78	$	-	$	10,575	$	2,707	$	-	$	13,360
Accounts receivable		-		-		55,073		2,939		(570)		57,442
Due from affiliates		234,746		-		-		-		(230,831)		3,915
Derivative instruments		-		-		27,485		-		-		27,485
Prepaid and other current assets		-		-		1,718		141		-		1,859
Total current assets		234,824		-		94,851		5,787		(231,401)		104,061
Noncurrent assets
Oil and natural gas properties and other property and equipment, net		-		-		1,591,015		13,968		-		1,604,983
Derivative instruments		-		-		62,131		-		-		62,131
Investment in subsidiaries		711,734		-		16,478		-		(728,212)		-
Other assets		4,663		-		20,176		19,913		-		44,752
Total noncurrent assets		716,397		-		1,689,800		33,881		(728,212)		1,711,866
Total assets	$	951,221	$	-	$	1,784,651	$	39,668	$	(959,613)	$	1,815,927

Liabilities and Partners' Capital
Current liabilities
Current portions of asset retirement obligations	$	-	$	-	$	4,310	$	-	$	-	$	4,310
Due to affiliates		-		-		230,831		-		(230,831)		-
Derivative instruments		-		-		11,233		-		-		11,233
Accrued and other liabilities		25,718		-		52,100		1,797		(570)		79,045
Total current liabilities		25,718		-		298,474		1,797		(231,401)		94,588
Noncurrent liabilities
Long-term debt		296,593		-		615,000		-		-		911,593
Derivative instruments		-		-		6,251		-		-		6,251
Asset retirement obligations		-		-		145,893		5,118		-		151,011
Other liabilities		-		-		7,299		7,726		-		15,025
Total noncurrent liabilities		296,593		-		774,443		12,844		-		1,083,880
Partners' capital
QR Energy, LP partners' capital		628,910		-		711,734		25,027		(736,761)		628,910
Noncontrolling interest		-		-		-		-		8,549		8,549
Total partners' capital		628,910		-		711,734		25,027		(728,212)		637,459
Total liabilities and partners' capital	$	951,221	$	-	$	1,784,651	$	39,668	$	(959,613)	$	1,815,927



Condensed Consolidating Statements of Operations

		Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations		Consolidated
Three Months Ended March 31, 2014
Total revenues	$	-	$	-	$	117,417	$	6,457	$	(1,251)	$	122,623
Expenses
Production and disposal and related expenses		-		-		46,019		5,851		(1,251)		50,619
Depreciation, depletion and amortization		-		-		29,735		101		-		29,836
General and administrative		1,814		-		8,341		-		-		10,155
Accretion of asset retirement obligations and acquisition and transaction costs		-		-		5,715		74		-		5,789
Total expenses		1,814		-		89,810		6,026		(1,251)		96,399
Operating income		(1,814)		-		27,607		431		-		26,224
Loss on commodity derivative contracts		-		-		(23,165)		-		-		(23,165)
Gain (loss) on Deferred Class B unit obligation		(5,240)		-		-		-		-		(5,240)
Interest expense, net, income tax expense and other income, net		(7,244)		-		(5,063)		92		-		(12,215)
Equity in earnings (loss)		(312)		-		309		-		3		-
Net (loss) income		(14,610)		-		(312)		523		3		(14,396)
Less: Net income attributable to noncontrolling interest		-		-		-		-		214		214
Net income (loss) attributable to QR Energy, LP	$	(14,610)	$	-	$	(312)	$	523	$	(211)	$	(14,610)

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Condensed Consolidating Statements of Comprehensive Income

		Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations		Consolidated
Three Months Ended March 31, 2014
Net income (loss)	$	(14,610)	$	-	$	(312)	$	523	$	3	$	(14,396)
Other comprehensive income, net of tax:
Reclassification adjustment for avail-for-sale securities		-		-		-		(14)		-		(14)
Change in fair value of available-for-sale securities		34				34		73		(68)		73
Pension and postretirement benefit:
Actuarial gain		(25)				(25)		(44)		50		(44)
Total other comprehensive income		9		-		9		15		(18)		15
Total comprehensive income (loss)		(14,601)		-		(303)		538		(15)		(14,381)
Less: Comprehensive income attributable to noncontrolling interest		-		-		-		-		220		220
Comprehensive income (loss) attributable to QR Energy, LP	$	(14,601)	$	-	$	(303)	$	538	$	(235)	$	(14,601)



Condensed Consolidating Statements of Cash Flows

		Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations		Consolidated
Three Months Ended March 31, 2014
Net cash (used in) provided by operating activities	$	(15,083)	$	-	$	57,589	$	(336)	$		$	42,170
Cash flows from investing activities
Additions to oil and natural gas properties		-		-		(29,107)		(726)		-		(29,833)
Acquisitions		-		-		(29,016)				-		(29,016)
Distributions from subsidiaries		51,924		-		-		-		(51,924)		-
Proceeds from sale of available-for-sale securities		-		-		-		614		-		614
Purchases of available-for-sale securities		-		-		-		(189)		-		(189)
Net cash (used in) provided by investing activities		51,924		-		(58,123)		(301)		(51,924)		(58,424)
Cash flows from financing activities
Distributions to unitholders		(35,422)		-		-		-		-		(35,422)
Proceeds from bank borrowings		-		-		63,000		-		-		63,000
Distributions to Parent		-		-		(51,924)		-		51,924		-
Other		(1,424)		-		-		-		-		(1,424)
Net cash (used in) provided by financing activities		(36,846)		-		11,076		-		51,924		26,154
Net increase (decrease) in cash		(5)		-		10,542		(637)		-		9,900
Cash at beginning of period		78		-		10,575		2,707		-		13,360
Cash at end of period	$	73	$	-	$	21,117	$	2,070	$	-	$	23,260

NOTE 21 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after March 31, 2014, through the issuance of the financial statements.

On March 28, 2014, the Board of Directors approved the first monthly distribution of $0.1625 per unit with respect to the first quarter of 2014 which was paid in April 2014 to the unitholders of record as of April 9, 2014.

On April 21, 2014, we entered into the seventh amendment to the Credit Agreement, which reduced the borrowing base from $950 million to $900 million.

On April 24 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the first quarter of 2014 which was paid in May 2014 to the unitholders of record as of May 8, 2014.

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

The following discussion and analysis should be read in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our 2013 Annual Report and the consolidated financial statements and related notes therein. Our 2013 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 2013 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 2013 Annual Report.

Overview

Our general partner is QRE GP, LLC (“general partner” or “QRE GP”). As a result of the GP Buyout Transaction, QRE GP became a 100% owned subsidiary of the Partnership. We conduct our operations through our 100% owned subsidiary QRE Operating, LLC (“OLLC”). Our 100% owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities. We also have a controlling interest in East Texas Saltwater Disposal Company (“ETSWDC”), a privately held Texas corporation. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil production in the East Texas Oil Field.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploitation activities or acquire properties with existing production. The amount we realize for our production depends predominately upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differential and other factors. These risk factors are mitigated by our hedging program under which we hedge approximately 65% to 85% of our current and anticipated production over the next three-to-five years. Oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. Oil and natural gas prices have increased in the last 12 months. The unweighted arithmetic average first day of-the-month prices for the prior 12 months increased to $98.43/Bbl for oil and increased to $3.98/MMbtu for natural gas as of March 31, 2014 from $96.91/Bbl for oil and $3.67/MMbtu for natural gas as of December 31, 2013. Declines in future oil and natural gas market prices could have a negative impact on our reserve value and could result in an impairment of our oil and gas properties. For example, a hypothetical 10% decrease in the 12 month average of oil prices would decrease the standardized measure of our estimated proved reserves by $312 million, and a hypothetical 10% decrease in the 12 month average of natural gas prices would decrease the standardized measure of our estimated reserves by $36 million. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

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Results of Operations



	Three Months Ended
	March 31, 2014			March 31, 2013
Revenues:
Oil sales	$	96,516	$	88,075
Natural gas sales		13,840		8,853
NGL sales		7,791		7,240
Disposal, processing and other		4,476		718
Total revenue		122,623		104,886
Operating Expenses:
Lease operating expenses		38,100		34,577
Production and other taxes		7,655		7,705
Processing and transportation		870		466
Total production expenses		46,625		42,748
Disposal and related expenses		3,994		-
Depreciation, depletion and amortization		29,836		30,815
Accretion of asset retirement obligations		2,134		1,732
General and administrative		10,155		10,096
Acquisition and transaction costs		3,655		561
Total operating expenses		96,399		85,952
Operating income		26,224		18,934
Other income (expense):
Gain (loss) on commodity derivative contracts, net		(23,165)		(16,006)
Loss on Deferred Class B unit obligation		(5,240)		-
Interest expense, net		(12,220)		(11,053)
Other income (expense), net		100		-
Total other income, net		(40,525)		(27,059)
Income before income taxes		(14,301)		(8,125)
Income tax (expense) benefit, net		(95)		(49)
Net income (loss)		(14,396)		(8,174)
Less: Net income (loss) attributable to noncontrolling interest		214		-
Net income (loss) attributable to QR Energy, LP	$	(14,610)	$	(8,174)
Sales volume data:
Oil (MBbls)		1,008		913
Natural gas (MMcf)		2,844		2,976
NGLs (MBbls)		219		192
Total (MBoe)		1,701		1,601
Average net sales volume (Boe/d)		18,900		17,789
Average sales price per unit (1):
Oil (per Bbl)	$	95.75	$	96.47
Natural gas (per Mcf)	$	4.87	$	2.97
NGLs (per Bbl)	$	35.58	$	37.71
Average unit cost per Boe:
Lease operating expense	$	22.40	$	21.60
Production and other taxes	$	4.50	$	4.81
Depreciation, depletion and amortization	$	17.54	$	19.25
General and administrative expenses	$	5.97	$	6.31

⁽¹⁾

Does not include the impact of derivative instruments.

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Results of Operations – Continued

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

We recorded a net loss of $14.6 million for the three months ended March 31, 2014 compared to net loss of $8.2 million for the three months ended March 31, 2013. The increase in the net loss is mainly due to an increase in losses on commodity derivatives and loss on deferred Class B unit obligation, partially offset by an increase in operating income.

Revenue:


		Three Months Ended March 31,
					Increase		Percentage
	2014		2013		(Decrease)		Change
Sales Volumes:
Oil (MBbls)		1,008		913		95	10%
Natural gas (MMcf)		2,844		2,976		(132)	-4%
NGL (MBbl)		219		192		27	14%
Total (MBoe)		1,701		1,601		100	6%

Average sales prices per unit: (1)
Oil (per Bbl)	$	95.75	$	96.47	$	(0.72)	-1%
Natural gas (per Mcf) (2)		4.87		2.97		1.90	64%
NGL (per Bbl)		35.58		37.71		(2.13)	-6%
Total (per Boe)	$	69.46	$	65.06	$	4.40	7%

Revenues:
Oil sales	$	96,516	$	88,075	$	8,441	10%
Natural gas sales		13,840		8,853		4,987	56%
NGL sales		7,791		7,240		551	8%
Disposal, processing and other		4,476		718		3,758	523%
Total revenue	$	122,623	$	104,886	$	17,737	17%

⁽¹⁾

Does not include the impact of derivative instruments.

⁽²⁾

Excluding the effects of change in prices on natural gas imbalances, the average sales prices per natural gas unit were $4.95 and $3.29 for the three months ended March 31, 2014 and 2013, respectively.

Total revenue increased by $17.7 million to $122.6 million due to increased sales volumes and prices. The increase in sales volumes is primarily due to a net increase in oil and NGL sales volumes mainly attributable to acquisitions in East Texas and improved performance at the Jay field following a turnaround to perform routine maintenance during the second quarter of 2013. This increase was partially offset by a decline in gas sales volumes related to downtime in certain fields. The increase in revenues was also attributable to higher natural gas prices due to increase in NYMEX prices. The increase in disposal, processing and other revenues is attributable to the operations of the ETSWDC, which we included in our results of operations beginning in August 2013 in connection with the 2013 East Texas Acquisition.

Production Expenses. Our production expenses increased by $3.9 million to $46.6 million mainly due to an increase in lease operating expenses and production and other taxes attributable to acquisitions in East Texas, as well as increased costs associated with the higher volumes for the Jay field, partially offset by lower costs in the Permian area due to improved operating efficiencies.

Disposal and Related Expenses. The disposal and related expenses of $4.0 million are attributable to the operations of ETSWDC, which we included in our results of operations beginning in August 2013 in connection with the 2013 East Texas Acquisition.

Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization (“DD&A”) expenses decreased by $1.0 million to $29.8 million, or $17.54 per Boe, mainly due to higher reserve quantities offset by higher production volumes as a result of acquisitions in the first quarter of 2014.

General and Administrative Expenses. Our general and administrative and other expenses increased by $0.1 million to $10.2 million, or $5.97 per Boe.

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Effects of Commodity Derivative Contracts. Our net loss on commodity derivative contracts increased by $7.2 million to $23.2 million. Gains and losses on commodity derivative contracts result from changes in the current and future commodity prices as compared to the fixed price of our open commodity derivative contracts.

Interest Expense, net. Net interest expense increased by $1.2 million to $12.2 million mainly due to an increase in interest expense attributable to an increase in the revolving credit facility which was used to fund acquisitions.

Other income, net. Other income of $0.1 million is mainly attributable to investment income for ETSWDC which was acquired in August 2013 in connection with the 2013 East Texas Acquisition.

Liquidity and Capital Resources

Our cash flow from operating activities for the three months ended March 31, 2014 was $42.2 million.

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under our credit facility, and debt and equity offerings. The capital markets are subject to volatility. Our exposure to current credit conditions includes our credit facility, debt securities, cash investments and counterparty performance risks. Volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

As of March 31, 2014, our cash and cash equivalents were $23.3 million, which includes $2.1 million that is held with a subsidiary that is not wholly-owned. As of March 31, 2014, our liquidity of $271.8 million consisted of $23.3 million of available cash and $248.5 million of availability under our credit facility after giving effect to $23.5 million of outstanding letters of credit. As of March 31, 2014, we had $678 million of borrowings outstanding. As of May 5, 2014 we had $693 million of borrowings outstanding with borrowing availability of $183.5 million ($900 million of borrowing base less $693 million of outstanding borrowing and $23.5 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. Pursuant to the semi-annual borrowing base redeterminations, the borrowing base of our revolving credit facility was increased to $950 million on October 15, 2013 and reduced to $900 million on April 21, 2014. In addition, we may request additional capacity for acquisitions of a minimum of the lesser of $50 million or 10% 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 up to $30 million. As of March 31, 2014, we had letters of credit in the amount of $23.5 million outstanding primarily related to a property reclamation deposit. Refer to Part I, Item 1. Consolidated Financial Statements – Note 12, Commitments and Contingencies for details.

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 sell and the operating and capital expenditures we incur. 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 12 months.

As of March 31, 2014, we had a positive working capital balance of $8.3 million.

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 production of our existing properties in a manner which is expected to be accretive to our unitholders. We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisitions of oil and natural gas properties in 2014 through a combination of cash, borrowings under our credit facility and the issuance of debt and equity securities. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. Although we closed an

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acquisition in August 2013 and January 2014, as discussed in Part I, Item 1. Consolidated Financial Statements – Note 3, Acquisitions, we cannot estimate further growth capital expenditures related to acquisitions, including potential acquisitions of producing properties from the Fund, as we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts. Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base. 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 2014, we have estimated our maintenance capital expenditures to be approximately $72 million.

During the three months ended March 31, 2014, we expended $33.0 million of capital expenditures. We currently expect 2014 total capital spending for the growth and maintenance of our oil and natural gas properties to be approximately $182.3 million. We have increased our expected capital spending to pursue growth opportunities in our various operating areas through drilling wells and recompleting or reactivating existing wells.

The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for the remainder of 2014. 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 Facility

Revolving Credit Facility

As of March 31, 2014, we had $678 million of borrowings outstanding under our revolving credit facility and $23.5 million of letters of credit outstanding resulting in $248.5 million of borrowing availability.

As of March 31, 2014, we were party to the Credit Agreement through April 2017 that governs our $1.5 billion revolving credit facility with a borrowing base of $950.0 million. The borrowing base is subject to redetermination on a semi-annual basis and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ price assumptions, and other various factors unique to each member bank. The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. In the future, we may be unable to access sufficient capital under our new credit facility as a result of (i) a decrease in our borrowing base due to subsequent borrowing base redeterminations, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

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

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. ETSWDC and QRE GP are not subsidiary guarantors under our Credit Agreement. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee ranging from 0.375% to 0.50% per annum.

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The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and to provide audited financial statements within 90 days of year end and quarterly unaudited financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of March 31, 2014, we were in compliance with all of the Credit Agreement covenants.

On April 21, 2014, we entered into the seventh amendment to the Credit Agreement, which reduced the borrowing base from $950 million to $900 million.

As of May 5, 2014 we had $693 million of borrowings outstanding under our revolving credit facility and $183.5 million of borrowing availability.

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 – Note 6, Derivative Activities.

Cash Flows

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



	Three Months Ended
	March 31, 2014		March 31, 2013
Net cash provided by (used in):
Operating activities	$	42,170	$	33,922
Investing activities		(58,424)		(16,230)
Financing activities		26,154		(33,948)

Operating Activities

Our cash flow from operating activities increased by $8.3 million to $42.2 million mainly due to changes in working capital for the three months ended March 31, 2013 attributable to the oil and natural gas properties acquired in 2012 and a decrease in cash receipts from settlements on commodity derivatives partially offset by higher operating margins.

Investing Activities

Our cash flow used in investing activities increased by $42.2 million to $58.4 million mainly due to acquisition expenditures and additions to our oil and natural gas properties.

Financing Activities

Our cash flow from financing activities increased by $60.1 million to $26.2 million mainly due to borrowings under our credit facility, partially offset by an increase in distributions paid to unitholders in 2014 and the management incentive fee paid to the general partner.

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Contractual Obligations

There were no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements as of March 31, 2014. Our level of capital expenditures will vary in the future periods depending on the success we experience in our acquisition, development and exploitation activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.

Off-Balance Sheet Arrangements

As of March 31, 2014, 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 consolidated financial statements, which have been prepared in accordance with U.S. GAAP. Preparation of these 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 2013 Annual Report during the three months ended March 31, 2014, except for those discussed in Part I, Item 1. Consolidated Financial Statements – Note 2 – Significant Accounting Policies.

Recent Accounting Pronouncements

There were no recent accounting pronouncements issued which were applicable to us in 2014.

Non-GAAP Financial Measures

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

Adjusted EBITDA

We define Adjusted EBITDA as net income from which we add or subtract the following:

Net interest expense, including gains and losses on interest rate derivative contracts;

Depreciation, depletion, and amortization;

Accretion of asset retirement obligations;

Gains or losses due to effects of change in prices on natural gas imbalances;

Gains or losses on commodity derivative contracts, net;

Gains or losses on deferred Class B unit obligation

Cash received or paid on the settlement of commodity derivative contracts, net;

Income tax expense or benefit;

Other income or expense;

Interest expense;

Impairments;

Non-cash general and administrative expenses, and acquisition and transaction costs;

Non-cash pension and postretirement expense or credit; and

Beginning with third quarter 2013, noncontrolling interest amounts attributable to each of the items above, as applicable, which revert the calculation back to the Adjusted EBITDA attributable the Partnership

Adjusted EBITDA to the Partnership 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.

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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 other companies because they may not calculate Adjusted EBITDA in the same manner.

Distributable Cash Flow

We define Distributable Cash Flow as Adjusted EBITDA less cash interest expense, estimated maintenance capital expenditures, distributions to preferred unitholders, and the management incentive fee as applicable to the periods prior to the GP Buyout Transaction. Estimated maintenance capital expenditures are calculated based on our estimate of the capital required to maintain our current production for five years, on average. This estimate is made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business.

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

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

The table below presents our calculation of Adjusted EBITDA and Distributable Cash Flow for the periods presented.


	Three Months Ended
	March 31, 2014		March 31, 2013
Reconciliation of net income (loss) to Adjusted EBITDA
and Distributable Cash Flow:
Net income	$	(14,396)	$	(8,174)
Loss (gain) on commodity derivative contracts, net		23,165		16,006
Cash received (paid) to settle commodity derivative contracts, net		1,206		9,310
Loss on Deferred Class B unit obligation		5,240		-
Loss (gain) on effect of change in prices on gas imbalances		250		926
Depletion, depreciation and amortization		29,836		30,815
Accretion of asset retirement obligations		2,134		1,732
Interest (income) expense		12,220		11,053
Other (income) expense		(100)		-
Income tax expense (benefit)		95		49
Non-cash general and administrative expenses and
acquisition and transaction costs		5,398		1,587
Noncontrolling interest		(247)		-
Adjusted EBITDA	$	64,801	$	63,304

Cash interest expense		(12,388)		(11,077)
Estimated maintenance capital expenditures		(18,000)		(17,000)
Distributions to preferred unitholders		(3,500)		(3,500)
Management incentive fee (1)		-		-
Distributable Cash Flow	$	30,913	$	31,727

⁽¹⁾

The management incentive fee was not applicable to the three months ended March 31, 2014 as a result of the GP Buyout Transaction. No management incentive fee was earned for the three months ended March 31, 2013.

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The increase in Adjusted EBITDA of $1.5 million to $64.8 million for the three months ended March 31, 2014 is mainly due to an increase in cash operating margins, partially offset by a decrease in cash receipts on settlements of commodity derivative contracts.

The decrease in Distributable Cash Flow of $0.8 million to $30.9 million for the three months ended March 31, 2014 is mainly due to an increase in cash interest expense which is mainly attributable to our revolving credit facility, and an increase in maintenance capital expenditures, partially offset by an increase in Adjusted EBITDA.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the first quarter of 2014 did not change materially from the disclosures in Item 7A of our 2013 Annual Report.

Derivative Instruments and Hedging Activity

We are exposed to various risks including energy commodity price risk. If 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 hedging 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 that we hedge through the use of our derivative instruments vary 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 hedging policies and objectives may change significantly as commodities prices or price futures change.

Our hedging 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.

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. We account for our derivative activities whereby each 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 – Note 6 – Derivative Activities for further details.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) we have evaluated, under the supervision and with the participation of our Chief Executive Officer, our principal executive officer, and Chief Financial Officer, our principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2014. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Based on this evaluation, the principal executive officer and the principal financial officer concluded that the Partnership’s disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2014.

Changes in Internal Control over Financial Reporting.

There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please see Part 1, Item 3 “Legal Proceedings” in our 2013 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 2013 Annual Report on Form 10-K.

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 June 27, 2013, by and among QRE Operating, LLC and an undisclosed private seller (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on July 2, 2013).
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			Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, dated as of December 12, 2013 (Incorporated herein by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed December 17, 2013).
3.5			Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of QR Energy, LP, dated as of March 2, 2014 (Incorporated herein by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed March 3, 2014).
3.6		---	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).
10.1			Sixth Amendment to the Credit Agreement dated as of February 28, 2014, 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 herein by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed March 3, 2014).
10.2			First Amendment to the QRE GP, LLC Long-Term Incentive Plan, adopted as of March 10, 2014 (Incorporated herein by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed March 19, 2014).
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

Ay

	By:	QRE GP, LLC,
		its General Partner
Dated: May 7, 2014	By:	/s/ Alan L. Smith
		Alan L. Smith
		Chief Executive Officer and Director
Dated: May 7, 2014	By:	/s/ Cedric W. Burgher
		Cedric W. Burgher
		Chief Financial Officer




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)




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




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




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


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PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	5
	Consolidated Balance Sheets as of March 31, 2014 (Unaudited) and December 31, 2013	5
	Unaudited Consolidated Statements of Operations for the Three Months Ended March 31, 2014 and 2013	6
	Unaudited Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2014 and 2013	7
	Unaudited Consolidated Statement of Changes in Partners' Capital for the Three Months Ended March 31, 2014	8
	Unaudited Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013	9
	Unaudited Notes to the Consolidated Financial Statements	10
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38
Item 4.	Controls and Procedures	38

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3.	Defaults Upon Senior Securities	39
Item 4.	Mine Safety Disclosure	39
Item 5.	Other Information	39
Item 6.	Exhibits	40

Signatures		41



QR ENERGY, LP
CONSOLIDATED BALANCE SHEETS
(In thousands, except unit amounts)

	March 31,		December 31,
	2014		2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	23,260	$	13,360
Accounts receivable		57,667		57,442
Due from affiliates		3,377		3,915
Derivative instruments		19,603		27,485
Prepaid and other current assets		1,650		1,859
Total current assets		105,557		104,061
Noncurrent assets:
Oil and natural gas properties, using the full cost method of accounting
Evaluated		1,974,363		1,905,110
Unevaluated		4,050		4,320
Gross oil and natural gas properties		1,978,413		1,909,430
Other property, plant and equipment		14,840		14,114
Less accumulated depreciation, depletion, and amortization		(348,396)		(318,561)
Total oil and natural gas properties and other property, plant and equipment, net		1,644,857		1,604,983
Derivative instruments		48,785		62,131
Other assets		40,292		44,752
Total noncurrent assets		1,733,934		1,711,866
Total assets	$	1,839,491	$	1,815,927

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Current portion of asset retirement obligations	$	4,461	$	4,310
Derivative instruments		13,874		11,233
Accrued and other liabilities		78,966		79,045
Total current liabilities		97,301		94,588
Noncurrent liabilities:
Long-term debt		974,723		911,593
Deferred Class B unit obligation		147,017		-
Derivative instruments		5,757		6,251
Asset retirement obligations		153,809		151,011
Deferred taxes		2,214		2,114
Other liabilities		12,462		12,911
Total noncurrent liabilities		1,295,982		1,083,880
Commitments and contingencies (see Note 12)
Partners' capital:
Class C convertible preferred unitholders (16,666,667 units issued and outstanding as of March 31, 2014 and December 31, 2013)		392,609		388,621
General partner (zero and 51,036 units issued and outstanding as of March 31, 2014 and December 31, 2013)		-		614
Class B unitholders (6,133,558 units issued and outstanding as of March 31, 2014 and December 31, 2013)		-		-
Public common unitholders (51,489,196 and 51,483,263 units issued and outstanding as of March 31, 2014 and December 31, 2013)		142,361		313,302
Affiliated common unitholders (7,145,866 units issued and outstanding as of March 31, 2014 and December 31, 2013)		(100,284)		(76,371)
Accumulated other comprehensive income		2,753		2,744
Total QR Energy, LP partners' capital		437,439		628,910
Noncontrolling interest		8,769		8,549
Total partners' capital		446,208		637,459
Total liabilities and partners' capital	$	1,839,491	$	1,815,927

See accompanying notes to the consolidated financial statements



QR ENERGY, LP
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except per unit amounts)

		Three Months Ended
		March 31, 2014		March 31, 2013
Revenues:
Oil and natural gas sales	$	118,147	$	104,168
Disposal, processing and other		4,476		718
Total revenues		122,623		104,886
Operating Expenses:
Production expenses		46,625		42,748
Disposal and related expenses		3,994		-
Depreciation, depletion and amortization		29,836		30,815
Accretion of asset retirement obligations		2,134		1,732
General and administrative		10,155		10,096
Acquisition and transaction costs		3,655		561
Total operating expenses		96,399		85,952
Operating income		26,224		18,934
Other income (expense):
Gain (loss) on commodity derivative contracts, net		(23,165)		(16,006)
Loss on Deferred Class B unit obligation		(5,240)		-
Interest expense, net		(12,220)		(11,053)
Other income , net		100		-
Total other income (expense), net		(40,525)		(27,059)
Income (loss) before income taxes		(14,301)		(8,125)
Income tax (expense) benefit, net		(95)		(49)
Net income (loss)		(14,396)		(8,174)
Less: Net income attributable to noncontrolling interest		214		-
Net income (loss) attributable to QR Energy, LP	$	(14,610)	$	(8,174)
Net income (loss) attributable to QR Energy, LP per limited partner unit:
Common unitholders' (basic and diluted)	$	(2.86)	$	(0.33)
Weighted average number of limited partner units outstanding:
Common units (basic and diluted)		58,631		58,445

See accompanying notes to the consolidated financial statements


QR ENERGY, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(In thousands)

	Three Months Ended
	March 31, 2014		March 31, 2013

Net income (loss)	$	(14,396)	$	(8,174)
Other comprehensive income, net of tax:
Reclassification adjustment for available-for-sale securities		(14)
Change in fair value of available-for-sale securities (1)		73		-
Pension and postretirement benefits:
Actuarial gain (2)		(44)		-
Total other comprehensive income		15		-
Total comprehensive income (loss)		(14,381)		(8,174)
Less: Comprehensive income attributable to noncontrolling interest		220		-
Comprehensive income (loss) attributable to QR Energy, LP	$	(14,601)	$	(8,174)

(1) Net of income taxes of $122 for the three months ended March 31, 2014.
(2) Net of income taxes of $(24) for the three months ended March 31, 2014.
See accompanying notes to the consolidated financial statements



QR ENERGY, LP
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (UNAUDITED)
(In thousands)

		Class C										Accumulated		Total
		Convertible						Limited Partners				Other		QR Energy, LP				Total
		Preferred		General		Class B		Public		Affiliated		Comprehensive		Partners'		Noncontrolling		Partners'
		Unitholders		Partner		Unitholders		Common		Common		Income		Capital		Interest		Capital
Balances - December 31, 2013	$	388,621	$	614	$	-	$	313,302	$	(76,371)	$	2,744	$	628,910	$	8,549	$	637,459
Recognition of unit-based awards		-		-		-		1,743		-		-		1,743		-		1,743
Reduction in units to cover individuals' tax withholding		-		-		-		(25)		-		-		(25)		-		(25)
Buyout of general partner		-		(141,777)		-		-		-		-		(141,777)		-		(141,777)
Distributions to unitholders		(3,500)		(17)		(2,962)		(25,449)		(3,484)		-		(35,412)		-		(35,412)
Amortization of discount on increasing rate distributions		3,988		-		-		-		-		-		3,988		-		3,988
Noncash distribution to preferred unitholders		(3,988)		-		-		-		-		-		(3,988)		-		(3,988)
Management incentive fee earned		-		(1,399)		-		-		-		-		(1,399)		-		(1,399)
Other comprehensive income, net of tax		-		-		-		-		-		9		9		6		15
Net income (loss)		7,488		142,579		2,962		(147,210)		(20,429)		-		(14,610)		214		(14,396)
Balances - March 31, 2014	$	392,609	$	-	$	-	$	142,361	$	(100,284)	$	2,753	$	437,439	$	8,769	$	446,208

See accompanying notes to the consolidated financial statements