ea7ac54c3f2f420



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


		Six Months Ended
		June 30, 2013		June 30, 2012
Cash flows from operating activities:
Net income	$	55,440	$	122,474
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization		57,478		49,610
Accretion of asset retirement obligations		3,490		2,697
Recognition of unit-based awards		3,185		768
General and administrative expense contributed by affiliates		-		18,019
Unrealized gains on derivative contracts		(19,807)		(76,880)
Other items		2,999		2,371
Changes in operating assets and liabilities:
Accounts receivable and other assets		(14,108)		(3,566)
Accounts payable and other liabilities		4,542		2,341
Net cash provided by operating activities		93,219		117,834
Cash flows from investing activities:
Additions to oil and natural gas properties		(39,028)		(76,721)
Acquisitions		(2,210)		(225,118)
Net cash used in investing activities		(41,238)		(301,839)
Cash flows from financing activities:
Proceeds from issuance of units		80		162,195
Management incentive fee to the General Partner		(748)		(1,730)
Distributions to unitholders		(70,752)		(45,351)
Distributions to the Predecessor		-		(18,884)
Proceeds from bank borrowings		15,000		96,500
Repayments on bank borrowings		(5,000)		-
Deferred financing costs		(1,826)		(3,608)
Other		(905)		(21)
Net cash provided by (used in) financing activities		(64,151)		189,101
Increase (decrease) in cash		(12,170)		5,096
Cash at beginning of period		31,836		17,433
Cash at end of period	$	19,666	$	22,529

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

Our general partner is QRE GP, LLC (“general partner” or “QRE GP”). We conduct our operations through our wholly owned subsidiary QRE Operating, LLC (“OLLC”). Our wholly owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities. Quantum Resources Management, LLC (“QRM”), a subsidiary of QA Holdings, LP, provides management and operational services for us and the Fund. In accordance with the services agreement (the “Services Agreement”) between us, QRE GP and QRM, beginning on January 1, 2013, QRM is entitled to the reimbursement of general and administrative charges from us based on the allocation of charges between the Fund and us. Prior to January 1, 2013, the Partnership was required to pay an administrative services fee equal to 3.5% of Adjusted EBITDA, as defined in the Services Agreement. Refer to Note 2 – Significant Accounting Policies for details on the allocation of general administrative expenses beginning on January 1, 2013.

As of June 30, 2013, our ownership structure comprised a 0.1% general partner interest, a 7.5% limited partner interest in us represented by 6,133,558 Class B units held by QRE GP, a 29.3% limited partner interest held by the Fund, comprised of common units and all of our preferred units, and a 63.1% limited partner interest held by the public unitholders. On February 22, 2013, in accordance with our partnership agreement, our general partner elected to convert 80% of their 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.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles in the United States (“U.S. GAAP”) for complete annual financial statements. During interim periods, the Partnership follows the accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Annual Report”), filed with the Securities and Exchange Commission (“SEC”). The unaudited consolidated financial statements for the three and six months ended June 30, 2013 and 2012 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. Prior period amounts have been revised to conform to current period presentation. Operating results for the three and six months ended June 30, 2013 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2013. 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 2012 Annual Report.

The Partnership’s historical financial statements previously filed with the SEC have been revised in this quarterly report on Form 10-Q to include the results attributable to properties acquired from the Fund in December 2012 as if the Partnership owned such assets for all periods presented by the Partnership including the period from January 1, 2012 to June 30, 2012 as the transaction was between entities under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the properties have been prepared from the Predecessor’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported. See our accounting policy for transactions between entities under common control set forth in Note 2 – Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in our 2012 Annual Report.

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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 2012 Annual Report. There have been no significant changes to these policies during the six months ended June 30, 2013, with the exception to the update below.

General and Administrative Expense Allocation

The Partnership reimburses QRM for general and administrative expenses allocated to us based on the estimated use of such services between us and the Fund. The fee 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 administrative services costs will be further divided to include the sponsor’s additional funds as well. QRM has 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.

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). The objective of this update is to provide enhanced disclosures that will enable the users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The amendment requires entities to disclose both gross information and net information about instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. This scope would include financial and derivative instruments that either offset in accordance with U.S. GAAP or are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with U.S. GAAP. This amendment became effective for annual reporting periods beginning on or after January 1, 2013, and the interim periods within those annual periods. This update, which expanded disclosures, was adopted by us in January 2013 and did not have a material impact on our financial position, results of operations or cash flows. Refer to Note 5 – Derivative Activities for details on the expanded disclosures.

In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The ASU clarifies that ordinary trade receivables and receivables are not in the scope of ASU 2011-11. This ASU issuance did not impact our adoption of ASU 2011-11 as noted above.

NOTE 3 – ACQUISITIONS

On December 4, 2012, we closed the acquisition of primarily oil properties located in East Texas (the “2012 East Texas Properties”) from a private seller for $214 million in cash, after customary purchase price adjustments (the “2012 East Texas Acquisition”). The acquisition had an effective date of November 1, 2012. During the first quarter 2013, we received the $2.3 million receivable from the seller that was recorded as a purchase price adjustment at the date of the sale.

On April 20, 2012, we closed the acquisition of primarily oil properties, almost all of which are located in the Ark-La-Tex area, from Prize Petroleum, LLC and Prize Petroleum Pipeline, LLC (collectively “Prize”) for $225 million in cash after customary purchase price adjustments (the “Prize Acquisition”). The acquisition had an effective date of January 1, 2012.

The Prize Acquisition and the 2012 East Texas Acquisition qualified as business combinations and were accounted for under the purchase method of accounting. Accordingly, we recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. The fair value measurements of the oil and gas properties and asset retirement obligations were measured using valuation techniques and unobservable inputs that convert future cash flows to a single discounted amount. The initial accounting for business combinations are not finalized, and are subject to adjustments to the provisional fair value amounts, for one full year from their respective acquisition dates due to further analysis of information that was available at the acquisition date. On April 20, 2013, we finalized the accounting for the Prize Acquisition with no adjustments to the purchase price discussed above.

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The following unaudited consolidated income statement information provides actual results for the three and six months ended June 30, 2013 and pro forma income statement information for the three and six months ended June 30, 2012, which assumes the Prize Acquisition and the 2012 East Texas Acquisition had occurred on January 1, 2011. 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				Six Months Ended
		(Unaudited)				(Unaudited)
	June 30, 2013		June 30, 2012		June 30, 2013		June 30, 2012
	Actual		Pro Forma		Actual		Pro Forma
Total revenues	$	105,430	$	103,498	$	210,316	$	219,761
Operating income	$	24,363	$	21,162	$	43,297	$	56,153
Net income	$	63,614	$	135,216	$	55,440	$	134,832
Net income per unit:
Common unitholders' (basic)	$	0.89	$	2.17	$	0.58	$	1.95
Common unitholders' (diluted)	$	0.77	$	1.70	$	0.58	$	1.66
Subordinated units (basic)	$	-	$	2.16	$	-	$	1.95
Subordinated units (diluted)	$	-	$	1.69	$	-	$	1.65

NOTE 4 – FAIR VALUE MEASUREMENTS

Our financial instruments, including cash, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Our 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.

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 June 30, 2013 and December 31, 2012. All fair values reflected below and on the consolidated balance sheet have been adjusted for nonperformance risk.



As of June 30, 2013		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	131,308	$	-	$	131,308	$	-
	$	131,308	$	-	$	131,308	$	-

Liabilities from commodity derivative instruments	$	5,876	$	-	$	5,876	$	-
Liabilities from interest rate derivative instruments		9,201		-		9,201		-
	$	15,077	$	-	$	15,077	$	-

As of December 31, 2012		Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	122,143	$	-	$	122,143	$	-
	$	122,143	$	-	$	122,143	$	-

Liabilities from commodity derivative instruments	$	13,484	$	-	$	13,484	$	-
Liabilities from interest rate derivative instruments		12,236		-		12,236		-
	$	25,720	$	-	$	25,720	$	-

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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 June 30, 2013 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 June 30, 2013 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy. Refer to Note 5 – Derivative Activities for further information on the derivative premiums.

Senior Notes – The fair value of 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 June 30, 2013 was $312.8 million.

There have been no transfers between levels within the fair value measurement hierarchy during the six months ended June 30, 2013.

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NOTE 5 – DERIVATIVE ACTIVITIES

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

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

Commodity Derivatives

Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. As such, future earnings are subject to fluctuations due to changes in the market price of oil, natural gas and natural gas liquids. 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 six months ended June 30, 2013, we entered into new oil swap and basis swap contracts with settlement dates ranging from 2013 through 2017. All of the new 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 $5.0 million and $4.9 million and are classified as other non-current liabilities on the consolidated balance sheet as of June 30, 2013 and December 31, 2012. 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 realized gain (loss) on derivative instruments.

We hold commodity derivative contracts to manage our exposure to changes in the price of oil and natural gas related to our oil and natural gas production. As of June 30, 2013, the notional volumes of our commodity derivative contracts were:



Commodity	Index		July 1 - Dec 31, 2013		2014		2015		2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		8,172		7,815		7,356		6,293		5,547
Average price ($/Bbls)		$	98.38	$	95.65	$	93.74	$	90.03	$	86.23
Hedged Volume (Bbls/d)	LLS		1,400		1,900
Average price ($/Bbls)		$	99.51	$	98.77
Basis
Hedged Volume (Bbls/d)	WTS/WTI		2,400		2,400
Average price ($/Bbls)		$	(1.90)	$	(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		30,391		26,622		7,191		11,350		10,445
Average price ($/MMBtu)		$	5.99	$	6.18	$	5.34	$	4.27	$	4.47
Basis Swaps ⁽¹⁾
Hedged Volume (MMBtu/d)	Henry Hub		18,446		17,066		14,400
Average price ($/MMBtu)		$	(0.17)	$	(0.19)	$	(0.19)
Collars
Hedged Volume (MMBtu/d)	Henry Hub		2,446		4,966		18,000		630		595
Average floor price ($/MMBtu)		$	6.50	$	5.74	$	5.00	$	4.00	$	4.00
Average ceiling price ($/MMBtu)		$	8.65	$	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.

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Interest Rate Derivatives

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

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:



	June 30, 2013				December 31, 2012
		Asset		Liability		Asset		Liability
		Derivatives		Derivatives		Derivatives		Derivatives
Commodity contracts	$	131,308	$	5,876	$	122,143	$	13,484
Interest rate contracts		-		9,201		-		12,236
	$	131,308	$	15,077	$	122,143	$	25,720

Commodity
Current	$	40,809	$	3,724	$	45,522	$	4,130
Noncurrent		90,499		2,152		76,621		9,354
	$	131,308	$	5,876	$	122,143	$	13,484
Interest
Current	$	-	$	4,524	$	-	$	4,597
Noncurrent		-		4,677		-		7,639
	$	-	$	9,201	$	-	$	12,236

Total Derivatives
Current	$	40,809	$	8,248	$	45,522	$	8,727
Noncurrent		90,499		6,829		76,621		16,993
	$	131,308	$	15,077	$	122,143	$	25,720

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


	June 30, 2013				December 31, 2012
		Asset		Liability		Asset		Liability
		Derivatives		Derivatives		Derivatives		Derivatives

Gross derivatives	$	131,308	$	15,077	$	122,143	$	25,720
Netting		(5,098)		(5,098)		(11,594)		(11,594)
Net derivatives	$	126,210	$	9,979	$	110,549	$	14,126

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The following table presents the impact of derivatives and their location within our unaudited consolidated statements of operations for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended				Six Months Ended
		June 30, 2013		June 30, 2012		June 30, 2013		June 30, 2012
Realized gains (losses):
Commodity contracts ⁽¹⁾	$	7,435	$	14,222	$	16,745	$	22,293
Interest rate swaps ⁽²⁾		(1,202)		(2,326)		(2,347)		(4,629)
Total	$	6,233	$	11,896	$	14,398	$	17,664

Unrealized gains (losses):
Commodity contracts ⁽¹⁾	$	42,088	$	112,375	$	16,772	$	79,169
Interest rate swaps ⁽²⁾		2,008		(2,703)		3,035		(2,289)
Total	$	44,096	$	109,672	$	19,807	$	76,880

Total gains (losses):
Commodity contracts ⁽¹⁾	$	49,523	$	126,597	$	33,517	$	101,462
Interest rate swaps ⁽²⁾		806		(5,029)		688		(6,918)
Total	$	50,329	$	121,568	$	34,205	$	94,544

⁽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 6 – 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” balance sheet caption during the period in which the obligation is incurred. We record the accretion of our ARO liabilities in “Accretion of asset retirement obligations” in our consolidated statements of operations. Payments to settle asset retirement obligations occur over the lives of the oil and natural gas properties.

Changes in our asset retirement obligations for the six months ended June 30, 2013 are presented in the following table:



		Six Months Ended
		June 30, 2013
Beginning of period	$	126,991
Revisions to previous estimates		2,494
Liabilities incurred		162
Liabilities settled		(3,000)
Accretion expense		3,490
End of period	$	130,137
Less: Current portion of asset retirement obligations		(1,562)
Asset retirement obligations - non-current	$	128,575

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NOTE 7 – ACCRUED AND OTHER LIABILITIES

As of June 30, 2013 and December 31, 2012, accrued and other liabilities consisted of the following:



		June 30, 2013		December 31, 2012
Accrued lease operating expenses	$	16,604	$	11,173
Accrued capital spending		17,674		6,109
Senior notes accrued interest		11,563		11,563
Accrued production and other taxes		7,352		7,401
Gas imbalance liability		4,913		5,351
Distributions payable		3,500		3,500
Other		2,910		1,187
Total accrued and other liabilities	$	64,516	$	46,284

NOTE 8 – LONG-TERM DEBT

As of June 30, 2013 and December 31, 2012, consolidated debt obligations consisted of the following:


		June 30, 2013		December 31, 2012
Revolving credit facility	$	480,000	$	470,000
9.25% Senior Notes ⁽¹⁾		296,334		296,076
Total long-term debt	$	776,334	$	766,076

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

⁽¹⁾	The amount is net of unamortized discount of $3.7 million and $3.9 million as of June 30, 2013 and December 31, 2012, 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 9 – Commitment 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”).

In December 2012, we entered into the fourth amendment to the Credit Agreement that became effective on January 15, 2013. The amendment, among other provisions, increased the borrowing base from $730 million to $900 million and increased the letters of credit commitment from $20 million to $30 million.

On May 1, 2013, our revolving credit facility borrowing base remained at $900 million as a result of our semi-annual borrowing base redetermination.

As of June 30, 2013, we had $480.0 million of borrowings outstanding and $23.5 million of letters of credit issued resulting in $396.5 million of borrowing availability under the Credit Agreement.

As of June 30, 2013, the Credit Agreement provided for a $1.5 billion revolving credit facility maturing on April 20, 2017, with a borrowing base of $900 million. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ pricing assumptions, and other various factors unique to each member bank. The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum.

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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 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 June 30, 2013, we were in compliance with all of the Credit Agreement covenants.

9.25% Senior Notes

On July 30, 2012, we and our wholly-owned subsidiary QRE FC, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of 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 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 15 – 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 June 30, 2013, we were in compliance with all financial and other covenants of the Senior Notes.

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NOTE 9 – COMMITMENTS AND CONTINGENCIES

Property Reclamation Deposit

As a part of our acquisition of certain oil producing properties from the Fund in December 2012, we acquired a property reclamation deposit and letters of credit related to future abandonment and remediation obligations. In an acquisition between ExxonMobil Corporation (the “Seller”) and the Fund in 2006, the Fund was required to deposit $10.7 million into an escrow account as security for abandonment and remediation obligations. As of June 30, 2013 and December 31, 2012, $10.7 million was recorded in other assets on the consolidated balance sheets related to the deposit. 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, the Fund was required to provide a $3.0 million letter of credit in favor of the Seller and an additional $3.0 million letter of credit each year through 2012 for a total of $23.4 million.

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 obligation. Under the arrangement with the outside interest owner, we carry the working interest until historical expenditures are recovered. Once the expenditures are recovered, we will not carry the interest but will retain the future development costs and abandonment obligation which is currently reflected in our asset retirement obligations as of June 30, 2013 and December 31, 2012. The cost of this future obligation is funded through current proceeds attributable to the owner’s interest.

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.

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 June 30, 2013 and December 31, 2012, we had approximately $1.7 million and $1.9 million in environmental liabilities related to the Prize Acquisition, respectively. 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.

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NOTE 10 — PARTNERS’ CAPITAL

Units Outstanding

The table below details the units outstanding as of June 30, 2013 and December 31, 2012, and the changes in outstanding units for the six months ended June 30, 2013. As of June 30, 2013, 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, 2012	16,666,667	51,036	-	51,299,278	7,145,866
Vested units awarded under our Long-Term Incentive
Performance Plan	-	-	-	26,324	-
Reduction in units to cover individuals' tax withholdings	-	-	-	(2,477)	-
Management incentive fee conversion	-	-	6,133,558	-	-
Balance - June 30, 2013	16,666,667	51,036	6,133,558	51,323,125	7,145,866

Class B Units

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. 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, 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.

The Class B units are immediately convertible into common units at the election 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.

As of June 30, 2013, QRE GP owns a 0.1% general partner interest in us, represented by 51,036 general partner units, and a 7.5% limited partnership interest in us, represented by 6,133,558 Class B units. QRE GP has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. QRE GP’s 7.6% interest in these distributions will be reduced if we issue additional units in the future and QRE GP does not contribute a proportionate share of capital to us to maintain its general and limited partnership interest.

Allocation of Net Income (Loss)

Net income (loss) is allocated to the preferred and Class B unitholders to the extent distributions are made or accrued to them during the period, and 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.

Cash Distributions

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

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


											Limited Partners
													Affiliated
Payment Date	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
(In thousands, except per unit amounts)
February 15, 2013	December 31, 2012	$	3,500	$	0.21	$	25	$	-	$	25,275	$	3,484	$	28,784	$	0.4875
May 15, 2013	December 31, 2012		-		-		-		2,990		-		-		2,990		0.4875
May 15, 2013	March 31, 2013		3,500		0.21		25		2,990		25,480		3,484		31,979		0.4875

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On July 24, 2013, the board of directors of QRE GP declared a $0.4875 per unit cash distribution for the second quarter 2013 which is payable on August 14, 2013 to unitholders of record at the close of business on August 7, 2013.

NOTE 11 – NET INCOME (LOSS) PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income per limited partner unit for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended				Six Months Ended
	June 30, 2013		June 30, 2012		June 30, 2013		June 30, 2012
Net income	$	63,614	$	130,700	$	55,440	$	122,474
Net loss attributable to predecessor operations		-		(31,575)		-		(30,584)
Distribution on Class C convertible preferred units		(3,500)		(3,500)		(7,000)		(7,000)
Amortization of preferred unit discount		(3,868)		(3,713)		(7,697)		(7,389)
Distribution on Class B units		(2,990)		-		(5,980)		-
Net income available to other unitholders		53,256		91,912		34,763		77,501
Less: general partners' interest in net income (loss)		36		(703)		770		2,455
Limited partners' interest in net income	$	53,220	$	92,615	$	33,993	$	75,046
Common unitholders' interest in net income	$	53,220	$	77,478	$	33,993	$	62,454
Subordinated unitholders' interest in net income	$	-	$	15,137	$	-	$	12,592
Net income per limited partner unit:
Common unitholders' (basic)	$	0.89	$	2.15	$	0.58	$	1.92
Common unitholders' (diluted)	$	0.77	$	1.67	$	0.58	$	1.60
Subordinated unitholders' (basic)	$	-	$	2.12	$	-	$	1.76
Subordinated unitholders' (diluted)	$	-	$	1.65	$	-	$	1.50
Weighted average number of limited partner units outstanding ⁽¹⁾:
Common units (basic)		59,556		36,114		58,455		32,486
Common units (diluted)		82,356		52,780		58,455		49,153
Subordinated units (basic and diluted)		-		7,146		-		7,146

⁽¹⁾

For the three and six months ended June 30, 2013 and 2012, we had weighted average preferred units outstanding of 16,666,667. For the three months ended June 30, 2013 and 2012, we had 6,133,558 and zero Class B units outstanding, respectively. For the six months ended June 30, 2013 and 2012, we had 4,961,597 and zero Class B units outstanding, respectively. 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 been included in the diluted earnings per unit calculation for the three months ended June 30, 2013 as they were dilutive for the period, but have not been included in the diluted earnings per unit calculation for the six months ended June 30, 2013, as they were anti-dilutive for the period. The preferred units were included in the diluted earnings per unit calculation for the three and six months ended June 30, 2012 as they were dilutive for the periods.

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), by the weighted average number of limited partner units outstanding during the three and six months ended June 30, 2013 and 2012.

NOTE 12 – UNIT-BASED COMPENSATION

The QRE GP, LLC Long-Term Incentive Plan (the “Plan”) was established for employees, officers, consultants and directors of QRE GP and its affiliates, including QRM, who perform services for us. The Plan consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the Plan is to provide additional incentive compensation to 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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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 June 30, 2013 and 2012, we recognized compensation expense related to the outstanding Restricted Units of $2.0 million and $0.4 million. For the six months ended June 30, 2013 and 2012, we recognized compensation expense related to the outstanding Restricted Units of $2.9 million and $0.8 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 and six months ended June 30, 2013, we recognized $0.2 million and $0.3 million of compensation expense related to the Performance Units. There were no Performance Units outstanding for the three and six months ended June 30, 2012.

The following table summarizes the activity of our Restricted Units and Performance Units for June 30, 2013:


		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, 2012	550	$	18.80	118	$	10.34
Granted	479		17.99	149		10.03
Forfeited	(50)		18.49	-		-
Vested	(26)		19.01	-		-
Unvested units, June 30, 2013	953	$	18.39	267	$	10.17

NOTE 13 – RELATED PARTY TRANSACTIONS

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

As of June 30, 2013, affiliates of the Fund owned 100% of QRE GP, and 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, QRE GP owned a 0.1% general partner interest in us, represented by 51,036 general partner units, and a 7.5% limited partner interest in us, represented by 6,133,558 Class B units.

Contracts with QRE GP and its Affiliates

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

Services Agreement

Beginning on January 1, 2013, 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,

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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 unaudited 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 and six months ended June 30, 2013, we were charged $7.7 and $16.1 million in allocated general and administrative expenses from QRM.

Through December 31, 2012, QRM was entitled to the payment of a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined under the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee. For the three and six months ended June 30, 2012, we were allocated $11.3 million and $21.6 million in general and administrative expenses, which included $1.9 million and $3.6 million of administrative services fees in accordance with the Services Agreement.

In connection with the management of our business, QRM provides services for invoicing and collection of our revenues as well as processing of payments to our vendors. Periodically, QRM remits cash to us for the net working capital received on our behalf. Changes in the affiliate receivable balances during the six months ended June 30, 2013 are included below:



Net affiliate receivable as of December 31, 2012	$	-
Revenues and other increases		181,548
Expenditures		(122,752)
Settlements from the Fund		(60,010)
Net affiliate payable as of June 30, 2013	$	(1,214)

Management Incentive Fee

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

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

·	Adjustments for our commodity derivative contracts;

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

·	Adjustments for conversions of the management incentive fee into Class B units.

For the six months ended June 30, 2013, the management incentive fee recognized was $0.7 million related to the fourth quarter 2012. No management incentive fee was earned related to the first quarter 2013 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.

Unless we experience a change in control, our general partner will not be permitted to convert the management incentive fee again until (i) the completion of the fourth full calendar quarter following the previous election and (ii) the gross management incentive fee base, as described in our partnership agreement, has increased to 115% of the gross management incentive fee base as of the immediately preceding conversion date.

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Long–Term Incentive Plan

The Plan provides compensation for employees, officers, consultants and directors of QRE GP and its affiliates, including QRM, who perform services for us. As of June 30, 2013 and December 31, 2012, 1,220,842 and 668,323 restricted units were outstanding under the Plan. For additional discussion regarding the Plan see Note 12 – Unit-Based Compensation.

Distributions of Available Cash to QRE GP and Affiliates

We generally make cash distributions to our common and affiliated common unitholders pro rata, including QRE GP and its affiliates. Refer to Note 10 – 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 14 – SUPPLEMENTAL CASH FLOW INFORMATION

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



		Six Months Ended
		June 30, 2013		June 30, 2012
Supplemental Cash Flow Information
Cash paid during the period for interest	$	22,647	$	16,392
Non-cash Investing and Financing Activities
Change in accrued capital expenditures		11,565		(1,414)
General and administrative expense allocated from the Fund		-		18,019
Distributions to the Predecessor		-		(18,884)
Amortization of increasing rate distributions⁽¹⁾		7,697		7,389

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

NOTE 15 – SUBSIDIARY GUARANTORS

On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. The Senior Notes, issued on July 30, 2012, are guaranteed by OLLC, a 100% owned subsidiary of the Partnership, and certain other future subsidiaries (the “Guarantor”, together with any future 100% owned subsidiaries that guarantee the Partnership’s Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned by the Partnership and the guarantees by the Subsidiaries are full and unconditional. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations. Refer to Note 8 – Long-Term Debt for details on the conditions of the Guarantor releases.

NOTE 16 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after June 30, 2013, through the issuance of the financial statements.

2013 East Texas Acquisition

On August 6, 2013, we closed the acquisition of primarily oil properties located in East Texas from a private seller for $109.2 million cash, subject to customary purchase price adjustments (the “2013 East Texas Acquisition”), using funds drawn on our revolving credit facility on August 5, 2013. In accordance with the purchase and sale agreement, we placed a deposit into escrow which was recorded in other assets in the consolidated balance sheet as of June 30, 2013. In addition, the 2013 East Texas Acquisition includes an interest in a saltwater disposal company that will result in us owning a controlling interest. The saltwater disposal company services the acquired properties.

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Second Quarter 2013 Distribution

On July 24, 2013, the board of directors of QRE GP declared a $0.4875 per unit distribution related to the second quarter 2013 which will be paid on August 14, 2013 to unitholders of record at the close of business on August 7, 2013. As a result of this declaration, a management incentive fee related to the second quarter 2013 in the amount of $1.3 million will be recognized during the three months ended September 30, 2013.

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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 2012 Annual Report and the consolidated financial statements and related notes therein. Our 2012 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 2012 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 2012 Annual Report.

Overview

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”). We conduct our operations through our wholly owned subsidiary QRE Operating, LLC (“OLLC”). Our wholly owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities. Quantum Resources Management, LLC (“QRM”), a subsidiary of QA Holdings, LP, provides management and operational services for us and the Fund. In accordance with the Services Agreement between us, QRE GP and QRM, beginning on January 1, 2013, QRM is entitled to the reimbursement of general and administrative charges from us based on the allocation of charges between the Fund and us pursuant to the Services Agreement. Prior to January 1, 2013, the Partnership was required to pay an administrative services fee equal to 3.5% of Adjusted EBITDA, as defined in the Services Agreement. Refer to Note 2 – Significant Accounting Policies for details on the allocation of general administrative expenses beginning on January 1, 2013.

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 prices have experienced a general decline in the last 12 months while natural gas has experienced an increase during the same period. The unweighted arithmetic average first day of-the-month prices for the prior 12 months decreased to $91.60/Bbl for oil and increased to $3.44/MMbtu for natural gas as of June 30, 2013 from $94.71/Bbl for oil and $2.76/MMbtu for natural gas as of December 31, 2012. 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 $285 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 $26 million. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Results of Operations

Because affiliates of the Fund own 100% of our general partner, each acquisition of assets from the Predecessor is considered a transfer of net assets between entities under common control. As a result, we are required to revise our financial statements to include the activities of all assets acquired from the Predecessor for all periods presented by the Partnership, similar to a pooling of interests, to include the financial position, results of operations, and cash flows of the assets acquired and liabilities assumed. The table set forth below includes the revised historical financial information for the three and six months ended June 30, 2012 as if the oil and natural gas properties acquired from the Predecessor in December 2012 were owned by us for all periods presented for the Partnership. These results are presented for illustrative purposes only and have been prepared from the Predecessor’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets during the periods reported.

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Results of Operations - Continued



	Three Months Ended					Six Months Ended
	June 30, 2013		June 30, 2012 ⁽¹⁾			June 30, 2013		June 30, 2012⁽¹⁾
Revenues:
Oil sales	$	84,666	$	72,599	$	172,741	$	143,594
Natural gas sales		12,592		7,080		21,445		18,981
NGL sales		7,380		8,762		14,620		19,025
Processing and other		792		915		1,510		1,860
Total revenue		105,430		89,356		210,316		183,460
Operating Expenses:
Lease operating expenses		34,541		29,097		69,118		54,722
Production and other taxes		7,083		6,253		14,788		12,496
Processing and transportation		865		794		1,331		1,693
Total production expenses		42,489		36,144		85,237		68,911
Depreciation, depletion and amortization		26,663		25,326		57,478		49,610
Accretion of asset retirement obligations		1,758		1,375		3,490		2,697
General and administrative and other		10,098		10,182		20,194		20,169
Acquisition and transaction costs		59		920		620		1,008
Total operating expenses		81,067		73,947		167,019		142,395
Operating income		24,363		15,409		43,297		41,065
Other income (expense):
Realized gains on commodity derivative contracts		7,435		14,222		16,745		22,293
Unrealized gains on commodity derivative contracts		42,088		112,375		16,772		79,169
Interest expense, net		(10,270)		(10,576)		(21,323)		(19,354)
Total other expense, net		39,253		116,021		12,194		82,108
Income before income taxes		63,616		131,430		55,491		123,173
Income tax expense, net		(2)		(730)		(51)		(699)
Net income	$	63,614	$	130,700	$	55,440	$	122,474
Sales volume data:
Oil (MBbls)		872		767		1,785		1,445
Natural gas (MMcf)		2,823		3,463		5,799		7,010
NGLs (MBbls)		228		187		420		358
Total (MBoe)		1,571		1,531		3,172		2,971
Average net sales volume (Boe/d)		17,264		16,824		17,525		16,324
Average sales price per unit ⁽²⁾:
Oil (per Bbl)	$	97.09	$	94.65	$	96.77	$	99.37
Natural gas (per Mcf)	$	4.46	$	2.04	$	3.70	$	2.71
NGLs (per Bbl)	$	32.37	$	46.86	$	34.81	$	53.14
Average unit cost per Boe:
Lease operating expense	$	21.99	$	19.01	$	21.79	$	18.42
Production and other taxes	$	4.51	$	4.08	$	4.66	$	4.21
Depreciation, depletion and amortization	$	16.97	$	16.54	$	18.12	$	16.70
General and administrative expenses	$	6.43	$	6.65	$	6.37	$	6.79

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

⁽²⁾	Does not include the impact of derivative instruments.

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Results of Operations – Continued

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

We recorded net income of $63.6 million for the three months ended June 30, 2013 compared to net income of $130.7 million for the three months ended June 30, 2012. The decrease in net income is mainly due to a decrease in realized and unrealized gains on commodity derivatives, partially offset by an increase in operating income.

Oil and Natural Gas Revenues:


		Three Months Ended June 30,
					Increase		Percentage
	2013		2012		(Decrease)		Change
Sales Volumes:
Oil (MBbls)		872		767		105	14%
Natural gas (MMcf)		2,823		3,463		(640)	-18%
NGL (MBbl)		228		187		41	22%
Total (MBoe)		1,571		1,531		40	3%

Average sales prices per unit: ⁽¹⁾
Oil (per Bbl)	$	97.09	$	94.65	$	2.44	3%
Natural gas (per Mcf)⁽²⁾		4.46		2.04		2.42	118%
NGL (per Bbl)		32.37		46.86		(14.49)	-31%
Total (per Boe)	$	66.61	$	57.77	$	8.84	15%

Revenues:
Oil sales	$	84,666	$	72,599	$	12,067	17%
Natural gas sales		12,592		7,080		5,512	78%
NGL sales		7,380		8,762		(1,382)	-16%
Total oil and natural gas revenues	$	104,638	$	88,441	$	16,197	18%

⁽¹⁾	Does not include the impact of derivative instruments.

⁽²⁾	Excluding unrealized gains and losses on natural gas imbalances, the average sales prices per natural gas unit were $3.98 and $2.34 for the three months ended June 30, 2013 and 2012, respectively.

Total oil and natural gas revenues increased by $16.2 million to $104.6 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 attributable to acquisitions during the second and fourth quarters of 2012 and improved gas processing recoveries for NGLs, partially offset by a decline in oil and NGL sales volumes related to a turnaround for the Jay field in the current period to perform routine maintenance. The net increase in oil and NGL sales volumes was partially offset by a decline in natural gas sales volumes due to natural declines, downtime in certain fields and improved gas processing recoveries resulting in lower natural gas sales volumes. The increase in overall prices is due to an increase in oil and natural gas prices partially offset by a decline in NGL prices.

Production Expenses. Our production expenses increased by $6.4 million to $42.5 million mainly due to an increase in lease operating expenses and production and other taxes attributable to acquisitions during the second and fourth quarters of 2012, which properties carry a higher operating cost per Boe as compared to our existing properties, as well as increased costs associated with a turnaround for the Jay field in the current period to perform routine maintenance.

Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization (“DD&A”) expenses increased by $1.4 million to $26.7 million, or $16.97 per Boe, mainly due to higher production volumes in the second quarter of 2013 as a result of the 2012 East Texas Acquisition in the fourth quarter of 2012, which properties carry a higher DD&A rate per Boe as compared to our existing properties.

General and Administrative and Other Expenses. Our general and administrative and other expenses decreased slightly by $0.1 million to $10.1 million, or $6.43 per Boe.

Effects of Commodity Derivative Contracts. Our realized gains on commodity derivative contracts decreased by $6.8 million to $7.4 million and unrealized gains on commodity derivative contracts decreased by $70.3 million to $42.1 million. Unrealized gains and losses result from changes in the future commodity prices as compared to the

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fixed price of our open commodity derivative contracts. Realized gains and losses result from the settlement of derivative contracts at the market price as compared to the fixed contract price.

Interest Expense, net. Net interest expense decreased by $0.3 million to $10.3 million mainly due to a net interest rate derivative gain and lower outstanding borrowings under our revolving credit facility, partially offset by an increase in interest expense attributable to the Senior Notes that were issued in July 2012.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

We recorded net income of $55.4 million for the six months ended June 30, 2013 compared to net income of $122.5 million for the six months ended June 30, 2012. The decrease in net income is mainly due to a decrease in realized and unrealized gains on commodity derivatives.

Oil and Natural Gas Revenues:


		Six Months Ended June 30,
					Increase		Percentage
	2013		2012		(Decrease)		Change
Sales Volumes:
Oil (MBbls)		1,785		1,445		340		24%
Natural Gas (MMcf)		5,799		7,010		(1,211)		-17%
NGL (MBbl)		420		358		62		17%
Total (MBoe)		3,172		2,971		201		7%

Average sales prices per unit: ⁽¹⁾
Oil (per Bbl)	$	96.77	$	99.37	$	(2.60)		-3%
Natural gas (per Mcf)⁽²⁾		3.70		2.71		0.99		37%
NGL (per Bbl)		34.81		53.14		(18.33)		-34%
Total (per Boe)	$	65.83	$	61.12	$	4.71		8%

Revenues:
Oil sales	$	172,741	$	143,594	$	29,147		20%
Natural Gas sales		21,445		18,981		2,464		13%
NGL sales		14,620		19,025		(4,405)		-23%
Total oil and natural gas revenues	$	208,806	$	181,600	$	27,206		15%

⁽¹⁾	Does not include the impact of derivative instruments.

⁽²⁾	Excluding unrealized gains and losses on natural gas imbalances, the average sales prices per natural gas unit were $3.62 and $2.67 for the six months ended June 30, 2013 and 2012, respectively.

Total oil and natural gas revenues increased by $27.2 million to $208.8 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 attributable to acquisitions during the second and fourth quarters of 2012 and improved gas processing recoveries for NGLs, partially offset by a decline in NGL sales volumes related to a turnaround for the Jay field in the current period to perform routine maintenance. The net increase in oil and NGL sales volumes was partially offset by a decline in natural gas sales volumes due to natural declines, downtime in certain fields and improved gas processing recoveries resulting in lower natural gas sales volumes. The increase in overall prices is due to the mix of our volumes despite declines in oil and NGL prices partially offset by an increase in natural gas prices.

Production Expenses. Our production expenses increased by $16.3 million to $85.2 million mainly due to an increase in lease operating expenses and production and other taxes attributable to acquisitions during the second and fourth quarters of 2012, which properties carry a higher operating cost per Boe as compared to our existing properties, as well as increased costs associated with a turnaround for the Jay field in the current period to perform routine maintenance.

Depreciation, Depletion and Amortization Expenses. Our depreciation, depletion and amortization (“DD&A”) expenses increased by $7.9 million to $57.5 million, or $18.12 per Boe, mainly due to higher production volumes attributable to acquisitions during the second and fourth quarters of 2012, which properties carry a higher DD&A rate per Boe as compared to our existing properties.

General and Administrative and Other Expenses. Our general and administrative and other expenses remained flat at $20.2 million, or $6.37 per Boe.

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Effects of Commodity Derivative Contracts. Our realized gains on commodity derivative contracts decreased by $5.6 million to $16.7 million and unrealized gains on commodity derivative contracts decreased by $62.4 million to $16.8 million. Unrealized gains and losses result from changes in the future commodity prices as compared to the fixed price of our open commodity derivative contracts. Realized gains and losses result from the settlement of derivative contracts at the market price as compared to the fixed contract price.

Interest Expense, net. Net interest expense increased by $1.9 million to $21.3 million mainly due to interest expense attributable to the Senior Notes that were issued in July 2012, partially offset by a decrease in a bridge loan commitment fee incurred during 2012, a decrease in net interest rate derivative losses, and lower outstanding borrowings under our revolving credit facility.

Liquidity and Capital Resources

Our cash flow from operating activities for the six months ended June 30, 2013 was $93.2 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.

On December 20, 2012, we entered into the Fourth Amendment of our Credit Agreement which, among other provisions, increased our borrowing base to $900 million from $730 million. The Fourth Amendment became effective on January 15, 2013.

As of June 30, 2013, our liquidity of $416.2 million consisted of $19.7 million of available cash and $396.5 million of availability under our credit facility after giving effect to $23.5 million of outstanding letters of credit. As of June 30, 2013, we had $480.0 million of borrowings outstanding. As of August 5, 2013 we had $580 million of borrowings outstanding with borrowing availability of $296.5 million ($900 million of borrowing base less $580 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. On May 1, 2013, as part of our semi-annual borrowing base redetermination, we were informed that the borrowing base of our revolving credit facility will remain at $900 million. In addition, we may request additional capacity for acquisitions of a minimum of the lesser of $50 million or ten percent of the then-existing borrowing base. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility.

A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands up to $30 million. As of June 30, 2013, 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 (Unaudited) – Note 9, Commitment 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 June 30, 2013, we had a positive working capital balance of $39.8 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

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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 2013 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 acquisition in August 2013, as discussed in Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 16, Subsequent Events, we cannot estimate further growth capital expenditures related to acquisitions, including potential acquisitions of producing properties from the Fund, as we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts. 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 2013, we have estimated our maintenance capital expenditures to be approximately $68.8 million.

During the six months ended June 30, 2013, we expended $39.0 million of capital expenditures. We currently expect 2013 total capital spending for the growth and maintenance of our oil and natural gas properties to be approximately $97.0 million.

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 2013. 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.

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Credit Facility

Revolving Credit Facility

As of June 30, 2013, we had $480.0 million of borrowings outstanding under our revolving credit facility and $23.5 million of letters of credit outstanding resulting in $396.5 million of borrowing availability.

As of August 5, 2013, we had $580 million of borrowings outstanding under our revolving credit facility and $296.5 million of borrowing availability.

On May 1, 2013, as part of our semi-annual borrowing base redetermination, we were informed that the borrowing base of our revolving credit facility will remain at $900 million.

As of June 30, 2013, we were party to the Credit Agreement through April 2017 that governs our $1.5 billion revolving credit facility with a borrowing base of $900 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. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee ranging from 0.375% to 0.50% per annum.

The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and to provide audited financial statements within 90 days of year end and quarterly unaudited financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of June 30, 2013, we were in compliance with all of the Credit Agreement covenants.

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Commodity Derivative Contracts

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

Cash Flows

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



	Six Months Ended
	June 30, 2013		June 30, 2012
Net cash provided by (used in):
Operating activities	$	93,219	$	117,834
Investing activities		(41,238)		(301,839)
Financing activities		(64,151)		189,101

Operating Activities

Our cash flow from operating activities decreased by $24.6 million to $93.2 million mainly due to changes in working capital attributable to the oil and natural gas properties acquired in the second and fourth quarters of 2012, an increase in allocated general and administrative expenses being reimbursed by us to QRM, a decrease in realized gains on commodity derivatives and an increase in cash interest expense mainly attributable to the Senior Notes issued in July 2012. These decreases were partially offset by higher operating margins due to the oil and natural gas properties acquired in the second and fourth quarters of 2012.

Investing Activities

Our cash flow used in investing activities decreased by $260.6 million to $41.2 million mainly due to acquisition expenditures related to the Prize Acquisition in the second quarter of 2012 and lower capital spending during the current period.

Financing Activities

Our cash flow from financing activities decreased by $253.3 million resulting in a use for the current period of $64.2 million mainly due to proceeds received from the unit offering in April 2012, lower bank borrowings in the current period, and an increase in distributions paid to unitholders due to additional units issued during 2012.

Contractual Obligations

There were no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements as of June 30, 2013. Our level of capital expenditures will vary in the future periods depending on the success we experience in our acquisition, development and exploitation activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.

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Off-Balance Sheet Arrangements

As of June 30, 2013, we have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited consolidated financial statements, which have been prepared in accordance with U.S. GAAP. Preparation of these unaudited consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our 2012 Annual Report during the six months ended June 30, 2013, except for those discussed in Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 2 – Significant Accounting Policies.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Part I, Item 1. Consolidated Financial Statements (Unaudited) – Note 2 – Significant Accounting Policies.

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:

Plus:

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

·	Depreciation, depletion, and amortization;

·	Accretion of asset retirement obligations;

·	Unrealized losses on natural gas imbalances;

·	Unrealized losses on commodity derivative contracts;

·	Income tax expense;

·	Impairments; and

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

Less:

·	Income tax benefit;

·	Interest income;

·	Unrealized gains on natural gas imbalances; and

·	Unrealized gains on commodity derivative contracts.

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

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

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

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

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

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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 applicable to the period. 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					Six Months Ended
	June 30, 2013		June 30, 2012 ⁽¹⁾			June 30, 2013		June 30, 2012 ⁽¹⁾
Reconciliation of net income (loss) to Adjusted EBITDA
and Distributable Cash Flow:
Net income	$	63,614	$	130,700	$	55,440	$	122,474
Unrealized gains on commodity derivative contracts		(42,088)		(112,375)		(16,772)		(79,169)
Unrealized loss (gain) on gas imbalances		(1,365)		1,032		(439)		(298)
Depletion, depreciation and amortization		26,663		25,326		57,478		49,610
Accretion of asset retirement obligations		1,758		1,375		3,490		2,697
Interest expense		10,270		10,576		21,323		19,354
Income tax expense		2		730		51		699
Non-cash general and administrative expenses and
acquisition and transaction costs		2,219		9,368		3,806		17,755
Adjusted EBITDA	$	61,073	$	66,732	$	124,377	$	133,122

Cash interest expense		(11,494)		(7,580)		(22,571)		(14,814)
Estimated maintenance capital expenditures		(17,000)		(15,750)		(34,000)		(31,000)
Distributions to preferred unitholders		(3,500)		(3,500)		(7,000)		(7,000)
Management incentive fee ⁽²⁾		(1,266)		772		(1,266)		(2,383)
Distributable Cash Flow	$	27,813	$	40,674	$	59,540	$	77,925

⁽¹⁾	The three and six months ended June 30, 2012 Adjusted EBITDA has been revised to include financial information for the assets acquired under common control.

⁽²⁾	The management incentive fee applicable to the three months ended June 30, 2013 will be recognized during the three months ended September 30, 2013.

The decrease in Adjusted EBITDA of $5.7 million to $61.1 million for the three months ended June 30, 2013 is mainly due to an increase in the allocated general and administrative expenses being reimbursed by us to QRM and a decrease in realized gains on commodity derivative contracts, partially offset by an increase in cash operating margins. The decrease in Adjusted EBITDA of $8.7 million to $124.4 million for the six months ended June 30, 2013 is mainly due to an increase in the allocated general and administrative expenses being reimbursed by us to QRM and a decrease in realized gains on commodity derivative contracts, offset by an increase in cash operating margins.

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The decrease in Distributable Cash Flow of $12.9 million to $27.8 million for the three months ended June 30, 2013 is mainly due to a decrease in Adjusted EBITDA, an increase in cash interest expense which is mainly attributable to the Senior Notes issued in July 2012, an increase in maintenance capital expenditures, and an increase in the management incentive fee. The decrease in Distributable Cash Flow of $18.4 million to $59.5 million for the six months ended June 30, 2013 is mainly due to a decrease in Adjusted EBITDA, an increase in cash interest expense which is mainly attributable to the Senior Notes issued in July 2012, an increase in maintenance capital expenditures, partially offset by a decrease in the management incentive fee.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the second quarter of 2013 did not change materially from the disclosures in Item 7A of our 2012 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 (Unaudited) – Note 5 – 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 June 30, 2013. 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 June 30, 2013.

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 June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please see Part 1, Item 3 “Legal Proceedings” in our 2012 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 2012 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.

Table of Contents

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		---	Certificate of Formation of QRE GP, LLC (Incorporated by reference to Exhibit 3.4 of the Partnership’s Registration Statement on Form S-1 (File No. 333-169664) filed on September 30, 2010).
3.5		---	Amended and Restated Limited Liability Company Agreement of QRE GP, LLC (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35010) filed on December 22, 2010).
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.

Table of Contents

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: August 7, 2013	By:	/s/ Alan L. Smith
		Alan L. Smith
		Chief Executive Officer and Director
Dated: August 7, 2013	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 o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)



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

	June 30,		December 31,
	2013		2012
	(Unaudited)
ASSETS
Current assets:
Cash	$	19,666	$	31,836
Accounts receivable		52,296		41,897
Due from general partner		7		165
Derivative instruments		40,809		45,522
Prepaid and other current assets		2,533		2,642
Total current assets		115,311		122,062
Noncurrent assets:
Oil and natural gas properties, using the full cost method of accounting
Evaluated		1,718,308		1,656,146
Unevaluated		4,860		11,500
Gross oil and natural gas properties		1,723,168		1,667,646
Less accumulated depreciation, depletion, and amortization		(260,854)		(203,377)
Total property and equipment, net		1,462,314		1,464,269
Derivative instruments		90,499		76,621
Other assets		27,795		23,575
Total noncurrent assets		1,580,608		1,564,465
Total assets	$	1,695,919	$	1,686,527

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Due to affiliates	$	1,214	$	-
Current portion of asset retirement obligations		1,562		1,426
Derivative instruments		8,248		8,727
Accrued and other liabilities		64,516		46,284
Total current liabilities		75,540		56,437
Noncurrent liabilities:
Long-term debt		776,334		766,076
Derivative instruments		6,829		16,993
Asset retirement obligations		128,575		125,565
Other liabilities		6,615		6,892
Total noncurrent liabilities		918,353		915,526
Commitments and contingencies (see Note 9)
Partners' capital:
Class C convertible preferred unitholders (16,666,667 units issued and outstanding
as of June 30, 2013 and December 31, 2012)		380,765		373,068
General partner (51,036 units issued and outstanding
as of June 30, 2013 and December 31, 2012)		683		710
Class B unitholders (6,133,558 and zero units issued and outstanding
as of June 30, 2013 and December 31, 2012)		-		-
Public common unitholders (51,323,125 and 51,299,278 units issued
and outstanding as of June 30, 2013 and December 31, 2012)		386,442		403,757
Affiliated common unitholders (7,145,866 units issued
and outstanding as of June 30, 2013 and December 31, 2012)		(65,864)		(62,971)
Total partners' capital		702,026		714,564
Total liabilities and partners' capital	$	1,695,919	$	1,686,527

See accompanying notes to the consolidated financial statements




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




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


TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements	4
	Consolidated Balance Sheets as of June 30, 2013 (Unaudited) and December 31, 2012	4
	Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	5
	Unaudited Consolidated Statement of Changes in Partners' Capital for the Six Months Ended June 30, 2013	6
	Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012	7
	Unaudited Notes to the Consolidated Financial Statements	8
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	34

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosure	35
Item 5.	Other Information	35
Item 6.	Exhibits	36

Signatures		37



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

		Three Months Ended				Six Months Ended
		June 30, 2013		June 30, 2012		June 30, 2013		June 30, 2012
Revenues:
Oil and natural gas sales	$	104,638	$	88,441	$	208,806	$	181,600
Processing and other		792		915		1,510		1,860
Total revenues		105,430		89,356		210,316		183,460
Operating Expenses:
Production expenses		42,489		36,144		85,237		68,911
Depreciation, depletion and amortization		26,663		25,326		57,478		49,610
Accretion of asset retirement obligations		1,758		1,375		3,490		2,697
General and administrative		10,098		10,182		20,194		20,169
Acquisition and transaction costs		59		920		620		1,008
Total operating expenses		81,067		73,947		167,019		142,395
Operating income		24,363		15,409		43,297		41,065
Other income (expense):
Realized gains on commodity derivative contracts		7,435		14,222		16,745		22,293
Unrealized gains on commodity derivative contracts		42,088		112,375		16,772		79,169
Interest expense, net		(10,270)		(10,576)		(21,323)		(19,354)
Total other income, net		39,253		116,021		12,194		82,108
Income before income taxes		63,616		131,430		55,491		123,173
Income tax expense, net		(2)		(730)		(51)		(699)
Net income	$	63,614	$	130,700	$	55,440	$	122,474
Net income per limited partner unit:
Common unitholders' (basic)	$	0.89	$	2.15	$	0.58	$	1.92
Common unitholders' (diluted)		0.77		1.67		0.58		1.60
Subordinated unitholders' (basic)		-		2.12		-		1.76
Subordinated unitholders' (diluted)		-		1.65		-		1.50
Weighted average number of limited partner units outstanding:
Common units (basic)		59,556		36,114		58,455		32,486
Common units (diluted)		82,356		52,780		58,455		49,153
Subordinated units (basic and diluted)		-		7,146		-		7,146

See accompanying notes to the consolidated financial statements



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

		Class C
		Convertible						Limited Partners				Total
		Preferred		General		Class B		Public		Affiliated		Partners'
		Unitholders		Partner		Unitholders		Common		Common		Capital
Balances - December 31, 2012	$	373,068	$	710	$	-	$	403,757	$	(62,971)	$	714,564
Recognition of unit-based awards		-		-		-		3,185		-		3,185
Unit issuance costs		-		-		-		(78)		-		(78)
Distributions to unitholders		(7,000)		(50)		(5,980)		(50,755)		(6,967)		(70,752)
Amortization of discount on increasing rate distributions		7,697		-		-		-		-		7,697
Noncash distribution to preferred unitholders		(7,697)		-		-		-		-		(7,697)
Management incentive fee earned		-		(748)		-		-		-		(748)
Other		-		1		-		1,142		(728)		415
Net income		14,697		770		5,980		29,191		4,802		55,440
Balances - June 30, 2013	$	380,765	$	683	$	-	$	386,442	$	(65,864)	$	702,026

See accompanying notes to consolidated financial statements