Breitburn Energy Partners LP - FORM 8-K - EX-99.2

Attached files

file	filename
8-K - FORM 8-K - Breitburn Energy Partners LP	d796723d8k.htm
EX-12.1 - EX-12.1 - Breitburn Energy Partners LP	d796723dex121.htm
EX-99.1 - EX-99.1 - Breitburn Energy Partners LP	d796723dex991.htm
EX-99.3 - EX-99.3 - Breitburn Energy Partners LP	d796723dex993.htm
EX-23.3 - EX-23.3 - Breitburn Energy Partners LP	d796723dex233.htm
EX-23.2 - EX-23.2 - Breitburn Energy Partners LP	d796723dex232.htm
EX-23.1 - EX-23.1 - Breitburn Energy Partners LP	d796723dex231.htm

Exhibit 99.2

INDEX TO FINANCIAL STATEMENTS

QR ENERGY, LP AUDITED CONSOLIDATED FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm			F-2

Consolidated Balance Sheets as of December 31, 2013 and 2012			F-3

Consolidated Statements of Operations for the Years ended December 31, 2013, 2012 and 2011			F-4

Consolidated Statements of Comprehensive Income for the Years ended December 31, 2013, 2012, and 2011			F-5

Consolidated Statement of Changes in Partners’ Capital for the Years ended December 31, 2013, 2012 and 2011			F-6

Consolidated Statements of Cash Flows for the Years ended December 31, 2013, 2012 and 2011			F-7

Notes to Consolidated Financial Statements			F-8


QR ENERGY, LP UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets as of June 30, 2014 (Unaudited) and December 31, 2013			F-55

Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013			F-56

Unaudited Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2014 and 2013			F-57

Unaudited Consolidated Statement of Changes in Partners’ Capital for the Six Months Ended June 30, 2014			F-58

Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013			F-59

Unaudited Notes to the Consolidated Financial Statements			F-60

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of QRE GP, LLC

and the Unitholders of QR Energy, LP

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, comprehensive income, changes in partners’ capital and cash flows present fairly, in all material respects, the financial position of QR Energy, LP and its subsidiaries (the “Partnership”) at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 3, 2014

F-2

QR ENERGY, LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)


	December 31, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	13,360		$	31,836
Accounts receivable		57,442			41,897
Due from affiliate		3,915			—
Due from general partner		—			165
Derivative instruments		27,485			45,522
Prepaid and other current assets		1,859			2,642

Total current assets		104,061			122,062

Noncurrent assets:
Oil and natural gas properties, using the full cost method of accounting
Evaluated		1,905,110			1,656,146
Unevaluated		4,320			11,500

Gross oil and natural gas properties		1,909,430			1,667,646
Other property, plant and equipment		14,114			—

Less accumulated depreciation, depletion and amortization		(318,561	)		(203,377	)

Total oil and natural gas properties and other property, plant and equipment, net		1,604,983			1,464,269
Derivative instruments		62,131			76,621
Other assets		44,752			23,575

Total noncurrent assets		1,711,866			1,564,465

Total assets	$	1,815,927		$	1,686,527

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of asset retirement obligations	$	4,310		$	1,426
Derivative instruments		11,233			8,727
Accrued and other liabilities		79,045			46,284

Total current liabilities		94,588			56,437

Noncurrent liabilities:
Long-term debt		911,593			766,076
Derivative instruments		6,251			16,993
Asset retirement obligations		151,011			125,565
Deferred taxes		2,114			102
Other liabilities		12,911			6,790

Total noncurrent liabilities		1,083,880			915,526

Commitments and contingencies (See Note 11)
Partners’ capital:
Class C convertible preferred unitholders (16,666,667 units issued and outstanding as of December 31, 2013 and 2012)		388,621			373,068
General partner (51,036 units issued and outstanding as of December 31, 2013 and 2012)		614			710
Class B unitholders (6,133,558 and zero units issued and outstanding as of December 31, 2013 and 2012)		—			—
Public common unitholders (51,483,263 and 51,299,278 units issued and outstanding as of December 31, 2013 and 2012)		313,302			403,757
Affiliated common unitholders (7,145,866 units issued and outstanding as of December 31, 2013 and 2012)		(76,371	)		(62,971	)
Accumulated other comprehensive income		2,744			—

Total QR Energy, LP Partners’ capital		628,910			714,564
Noncontrolling interest		8,549			—

Total partners’ capital		637,459			714,564

Total liabilities and partners’ capital	$	1,815,927		$	1,686,527

See accompanying notes to the consolidated financial statements

F-3

QR ENERGY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)


	Year Ended December 31,
	2013			2012			2011
Revenues:
Oil and natural gas sales	$	446,801		$	368,189		$	356,579
Disposal, processing and other		8,828			3,809			4,325

Total revenues		455,629			371,998			360,904

Operating Expenses:
Production expenses		174,101			143,938			132,227
Disposal and related operating expenses		6,597			—			—
Depreciation, depletion and amortization		115,184			105,796			94,993
Accretion of asset retirement obligations		7,456			5,648			4,593
General and administrative		41,901			42,275			37,315
Acquisition and transaction costs		1,487			4,000			—

Total operating expenses		346,726			301,657			269,128

Operating income (loss)		108,903			70,341			91,776
Other income (expense):
Gain (loss) on commodity derivative contracts, net		(1,217	)		53,071			47,860
Interest expense, net		(48,000	)		(43,133	)		(50,491	)
Other income (expense), net		1,589			—			—

Total other income (expense), net		(47,628	)		9,938			(2,631	)

Income (loss) before income taxes		61,275			80,279			89,145
Income tax (expense) benefit, net		353			(528	)		(850	)

Net income (loss)		61,628			79,751			88,295
Less: Net income (loss) attributable to noncontrolling interest		663			—			—

Net income (loss) attributable to QR Energy, LP	$	60,965		$	79,751		$	88,295

Net Income (loss) attributable to QR Energy, LP per limited partner unit:
Common unitholders’ (basic)	$	0.26		$	0.19		$	0.10
Common unitholders’ (diluted)		0.26			0.19			0.10
Subordinated unitholders’ (basic and diluted)		—			0.11			0.10
Weighted average number of limited partner units outstanding:
Common units (basic)		58,524			35,132			28,728
Common units (dilutive)		58,524			35,282			28,728
Subordinated units (basic and diluted)		—			6,970			7,146

See accompanying notes to the consolidated financial statements

F-4

QR ENERGY, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)


	Year ended December 31,
	2013			2012		2011

Net income	$	61,628		$	79,751	$	88,295

Other comprehensive income, net of tax:
Reclassification adjustment for available-for-sale securities		(18	)		—		—
Change in fair value on available-for-sale securities (1)		631			—		—
Pension and postretirement benefits:
Actuarial gain (2)		4,061			—		—

Total other comprehensive income		4,674			—		—

Total comprehensive income		66,302			79,751		88,295

Less: Comprehensive income attributable to noncontrolling interest		2,593			—		—


Comprehensive income attributable to QR Energy, LP	$	63,709		$	79,751	$	88,295

(1)	Net of income taxes of $223 for the year ended December 31, 2013.

(2)	Net of income taxes of $2,093 for the year ended December 31, 2013.

See accompanying notes to the consolidated financial statements

F-5

QR ENERGY, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)


				Class C Convertible									Limited Partners									Accumulated Other		Total QR Energy, LP			Non-		Total
	Predecessor’s			Preferred			General			Class B			Public			Affiliated						Comprehensive		Partners’			Controlling		Partners’
	Capital			Unitholders			Partner			Unitholders			Common			Common			Subordinated			Income		Capital			Interest		Capital
Balances - December 31, 2010	$	129,089		$	—		$	708		$	—		$	276,723		$	(48,898	)	$	(30,928	)	$	—	$	326,694		$	—	$	326,694
Proceeds from over-allotment		—			—			—			—			41,963			—			—			—		41,963			—		41,963
Distribution to the Fund		—			—			—			—			—			(25,727	)		(16,273	)		—		(42,000	)		—		(42,000	)
Distributions to the Predecessor		(25,507	)		—			—			—			—			—			—			—		(25,507	)		—		(25,507	)
Other contributions from affiliates		17,357			—			—			—			—			12,366			7,822			—		37,545			—		37,545
Recognition of unit-based awards		—			—			—			—			1,351			—			—			—		1,351			—		1,351
Reduction in units to cover individuals’ tax withholding		—			—			—			—			(215	)		—			—			—		(215	)		—		(215	)
Distributions to unitholders		—			(3,424	)		(63	)		—			(30,673	)		(19,854	)		(12,557	)		—		(66,571	)		—		(66,571	)
Book value of October 2011 Transferred Properties contributed by the Predecessor		(249,331	)		—			—			—			—			—			—			—		(249,331	)		—		(249,331	)
Fair value of Preferred Units issued to the Fund		—			354,500			—			—			—			—			—			—		354,500			—		354,500
Fair value of Preferred Units in excess of net assets received from the Fund		—			—			(102	)		—			(49,491	)		(32,380	)		(20,481	)		—		(102,454	)		—		(102,454	)
Amortization of discount on increasing rate distributions		—			3,638			—			—			—			—			—			—		3,638			—		3,638
Noncash distribution to preferred unitholders		—			(3,638	)		—			—			—			—			—			—		(3,638	)		—		(3,638	)
Management incentive fee earned		—			—			(1,572	)		—			—			—			—			—		(1,572	)		—		(1,572	)
Net income		76,249			7,062			1,575			—			1,648			1,079			682			—		88,295			—		88,295

Balances - December 31, 2011	$	(52,143	)	$	358,138		$	546		$	—		$	241,306		$	(113,414	)	$	(71,735	)	$	—	$	362,698		$	—	$	362,698

Distributions to the Predecessor		(37,270	)		—			—			—			—			—			—			—		(37,270	)		—		(37,270	)
Proceeds from unit offerings		—			—			272			—			376,938			—			—			—		377,210			—		377,210
Book value of December 2012 Transferred Properties contributed by the Predecessor		45,578			—			—			—			—			—			—			—		45,578			—		45,578
Other contributions from affiliates		6,485			—			—			—			—			4,985			26,606			—		38,076			—		38,076
Recognition of unit-based awards		—			—			—			—			3,252			—			—			—		3,252			—		3,252
Reduction in units to cover individuals’ tax withholding		—			—			—			—			(322	)		—			—			—		(322	)		—		(322	)
Distributions to unitholders		—			(14,000	)		(60	)		—			(55,005	)		—			(10,362	)		—		(79,427	)		—		(79,427	)
Conversion of subordinated units		—			—			—			—			—			(53,122	)		53,122			—		—			—		—
Amortization of discount on increasing rate distributions		—			14,930			—			—			—			—			—			—		14,930			—		14,930
Noncash distribution to preferred unitholders		—			(14,930	)		—			—			—			—			—			—		(14,930	)		—		(14,930	)
Affiliated unit sale to public		—			—			—			—			(113,325	)		113,325			—			—		—			—		—
Consideration paid in excess of the December 2012 Transferred Properties received from the Fund		—			—			(59	)		—			(60,390	)		(8,412	)		—			—		(68,861	)		—		(68,861	)
Management incentive fee earned		—			—			(6,121	)		—			—			—			—			—		(6,121	)		—		(6,121	)
Net income		37,350			28,930			6,132			—			11,303			(6,333	)		2,369			—		79,751			—		79,751

Balances - December 31, 2012	$	—		$	373,068		$	710		$	—		$	403,757		$	(62,971	)	$	—		$	—	$	714,564		$	—	$	714,564

Recognition of unit-based awards		—			—			—			—			6,880			—			—			—		6,880			—		6,880
Reduction in units to cover individuals’ tax withholding														(583	)										(583	)				(583	)
Unit issuance costs		—			—			—			—			(76	)		—			—			—		(76	)		—		(76	)
Distribution to unitholders		—			(14,000	)		(108	)		(12,839	)		(110,184	)		(15,096	)		—			—		(152,227	)		—		(152,227	)
Amortization of discount on increasing rate distributions		—			15,553			—			—			—			—			—			—		15,553			—		15,553
Noncash distribution to preferred unitholders		—			(15,553	)		—			—			—			—			—			—		(15,553	)		—		(15,553	)
Management incentive fee earned		—			—			(3,357	)		—			—			—			—			—		(3,357	)		—		(3,357	)
Noncontrolling interest in connection with acquisition		—			—			—			—			—			—			—			—		—			5,956		5,956
Other		—			—			1			—			836			(837	)		—			—		—			—		—
Other comprehensive income, net of tax		—			—			—			—			—			—			—			2,744		2,744			1,930		4,674
Net income		—			29,553			3,368			12,839			12,672			2,533			—			—		60,965			663		61,628

Balances - December 31, 2013	$	—		$	388,621		$	614		$	—		$	313,302		$	(76,371	)	$	—		$	2,744	$	628,910		$	8,549	$	637,459

See accompanying notes to the consolidated financial statements

F-6

QR ENERGY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Year Ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Net income (loss) (1)	$	61,628		$	79,751		$	88,295
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		115,184			105,796			94,993
Accretion of asset retirement obligations		7,456			5,648			4,593
Amortization of deferred financing costs		2,424			2,898			2,101
Recognition of unit-based awards		6,880			3,252			1,351
General and administrative expense contributed by affiliates		—			38,076			34,721
Loss (gain) on derivative contracts, net		4,130			(42,850	)		(18,434	)
Cash received (paid) on settlement of derivative contracts		20,161			27,863			(76,565	)
Deferred income (benefit) tax expense		(304	)		372			849
Other items		2,935			2,075			357
Changes in operating assets and liabilities:
Accounts receivable and other assets		(21,762	)		(8,531	)		(29,386	)
Accounts payable and other liabilities		3,413			12,800			9,682

Net cash provided by operating activities		202,145			227,150			112,557

Cash flows from investing activities:
Additions to oil and natural gas properties		(88,247	)		(127,352	)		(70,426	)
Acquisitions, net of cash acquired		(128,234	)		(468,009	)		(3,044	)
Proceeds from sale of oil and natural gas properties		—			3,082			1,327
Proceeds from sale of available-for-sale securities		8,535			—			—
Purchases of available-for-sale securities		(10,249	)		—			—

Net cash used in investing activities		(218,195	)		(592,279	)		(72,143	)

Cash flows from financing activities:
Proceeds from unit offering, net of offering costs		87			376,938			41,963
Proceeds from senior note offering, net of underwriter discount		—			295,860			—
Distributions to the Fund		—			—			(42,000	)
Proceeds from issuance of units to the general partner		—			115			715
Management incentive fee paid to the general partner		(3,357	)		(7,692	)		—
Distributions to unitholders		(141,582	)		(96,472	)		(46,026	)
Contributions from (distributions to) the Predecessor		—			(34,973	)		(25,507	)
Proceeds from bank borrowings		180,000			476,500			275,000
Repayments on bank borrowings		(35,000	)		(506,500	)		—
Repayment of debt assumed from the Fund		—			(115,000	)		(227,000	)
Units withheld for employee payroll tax obligation		(583	)		(322	)		—
Deferred financing costs		(1,991	)		(8,922	)		(2,321	)

Net cash provided by (used in) financing activities		(2,426	)		379,532			(25,176	)

Increase (decrease) in cash		(18,476	)		14,403			15,238
Cash and cash equivalents at beginning of period		31,836			17,433			2,195

Cash and cash equivalents at end of period	$	13,360		$	31,836		$	17,433

(1)	Includes net income attributable to noncontrolling interest.

See accompanying notes to the consolidated financial statements

F-7

QR Energy, LP

Notes to Consolidated Financial Statements

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

NOTE 1 — ORGANIZATION AND OPERATIONS

QR Energy, LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed on September 20, 2010 to acquire oil and gas assets from our affiliated entity, QA Holdings, LP (the “Predecessor”) and other third party entities in order to enhance and exploit oil and gas properties. We currently have oil and gas related properties in Alabama, Arkansas, Florida, Kansas, Louisiana, Michigan, New Mexico, Oklahoma and Texas. 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 (or “QRE GP”). We conduct our operations through our 100% owned subsidiary QRE Operating, LLC (“OLLC”). Our 100% owned subsidiary, QRE Finance Corporation (“QRE FC”), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities. In connection with our acquisition of certain East Texas oil properties (see Note 4 – Acquisitions), we acquired a controlling interest in East Texas Saltwater Disposal Company (“ETSWDC”), a privately held Texas corporation. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil produced in certain East Texas oilfields.

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 – Summary of Significant Accounting Policies for details on the allocation of general and administrative expenses beginning on January 1, 2013.

As of December 31, 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 29.2% limited partner interest held by the Fund, comprised of common units and all of our preferred units, and a 63.2% limited partner interest held by the public unitholders. 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.

On March 2, 2014 we completed a transaction related to our general partner interest pursuant to a Contribution Agreement. See Note 22 – Subsequent Events for more information.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2013 and 2012. These financial statements also include the results of our operations, our changes in comprehensive income, changes in partners’ capital, and cash flows for the years ended December 31, 2013, 2012, and 2011. These consolidated financial statements include all of our wholly-owned subsidiaries and investments we are deemed to have control.

These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. When necessary, certain reclassifications have been made to the previous years to conform to the 2013 presentation.

F-8

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates particularly significant to the financial statements include the following:

•

Estimates of our reserves of oil, natural gas and natural gas liquids (“NGL”);

•

Future cash flows from oil and gas properties;

•

Depreciation, depletion and amortization expense;

•

Asset retirement obligations;

•

Pension and postretirement obligations;

•

Fair values of derivative instruments and investments;

•

Unit based compensation;

•

Fair values of assets acquired and liabilities assumed from business combinations; and

•

Natural gas imbalances.

As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuous changes in the economic environment will be reflected in the financial statements in future periods.

There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including future costs to dismantle, dispose and restore our properties. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. Our cash and cash equivalents consist of cash in banks and investments in money market accounts. The majority of cash and cash equivalents are maintained with a major financial institution in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We use the specific identification method of providing allowances for doubtful accounts. As of December 31, 2013 and 2012, the allowance for doubtful accounts was not material.

Property and Equipment

Oil and Natural Gas Properties. We account for our oil and natural gas exploration and development activities under the full cost method of accounting. Under this method, all costs associated with property exploration and development (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and direct overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities are capitalized. Gains and losses are not recognized on the sale of disposition of oil and gas properties unless the adjustment would significantly alter the relationship between capitalized costs and proved oil and gas reserves attributable to a cost center. Under full cost accounting, cost centers are established on a country-by-country basis. We have one cost center as we operate exclusively in the United States. Expenditures for maintenance and repairs are charged to expense in the period incurred, with the exception of workovers resulting in an increase in proved reserves which are capitalized.

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Ceiling Test. Pursuant to full cost accounting rules, we must perform a ceiling test at the end of each quarter related to our proved oil and natural gas properties. The ceiling test provides that capitalized costs less related accumulated depreciation, depletion and amortization may not exceed an amount equal to (1) the present value of future net revenue from estimated production of proved oil and natural gas reserves, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, discounted at 10% per annum; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any. If the net capitalized costs exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs.

The ceiling calculation utilizes prices calculated as a twelve-month average price using first day of the month prices and costs in effect as of the last day of the period are held constant. The prices used are adjusted for basis or location differentials, product quality, energy content and transportation fees. A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date.

There were no write-downs required by us during the years ended December 31, 2013, 2012, and 2011. Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that we could incur a write-down.

Depletion. The provision for depletion of proved oil and natural gas properties is calculated on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The Partnership and the Predecessor calculate depletion on a quarterly basis.

Unevaluated Properties. In connection with the Prize Acquisition, the 2013 East Texas Acquisition and the 2012 East Texas Acquisition, we acquired unevaluated properties which are not being depleted pending determination of the existence of proved reserves. Unevaluated properties are assessed quarterly to ascertain whether there is a probability of obtaining proved reserves in the future. When it is determined that these properties have been promoted to a proved reserve category or there is no longer any probability of obtaining proved reserves from the properties, the costs associated with these properties are transferred into the amortization base to be included in the depletion calculation and subject to the ceiling test. Unevaluated properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geological data obtained relating to the properties. Where it is not practical to assess properties individually as their costs are not individually significant, such properties are grouped for purposes of the periodic assessment.

Other Property, Plant and Equipment. Other property, plant and equipment consists of property and equipment related to the disposal of saltwater in our East Texas fields and are held at cost and depreciated on a straight-line basis over 5 to 25 years.

Transactions Between Entities Under Common Control

From time to time we enter into transactions whereby we receive a transfer of certain oil and natural gas assets from our Predecessor with units issued or cash paid us. We account for the net assets received using the historical book value of the Predecessor as these are transactions between entities under common control. Our historical financial statements have been revised to include the results attributable to the assets contributed from the Predecessor as if we owned such assets for all periods presented by the Partnership.

Oil and Natural Gas Properties Received. The historical book value of oil and natural gas properties received from the Predecessor is determined using the ratio of the value, based on a discounted cash flow model, of the reserves contributed to the total value of the Predecessor’s oil and gas reserves at the beginning of the earliest revised period. This ratio is then applied to the book value of oil and gas properties to determine the beginning book value of the contributed properties. This reserve ratio was also applied to determine the book value of any additions made to the assets contributed by the Predecessor during the revision period.

Long-Term Debt Assumed. The historical book value and related activity of long-term debt assumed from the Predecessor was determined by using the effective date amount of debt assumed per the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. The Partnership’s financial statements include the

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beginning IPO Closing Date balance, borrowings and repayments of the assumed debt to properly reflect these debt transactions as if the Partnership owned the October 2011 Transferred Properties and the December 2012 Transferred Properties for the periods presented by the Partnership.

Asset Retirement Obligations Received. The historical book value and related activity of asset retirement obligations received from the Predecessor was determined by using the specific obligations related to the properties listed in the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. These asset retirement balances as of the effective date of the purchase agreements and all related previous activity dating back to the IPO Closing Date are included in the Partnership’s financial statements.

Other Assets Received. The historical book value and related activity of other assets received from the Predecessor was determined by using the assets listed in the December 2012 Purchase Agreement. The balances of these assets as of the effective date of the December 2012 Purchase Agreement and all related previous activity dating back to the IPO Closing Date are included in the Partnership’s financial statements.

Derivative Instruments Received. The historical book value and related activity of commodity and interest rate derivative instruments received from the Predecessor was determined by using the instruments listed in the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. The balances of these derivative instruments as of the effective date of the purchase agreements and related previous unrealized gains and losses and modifications dating back to the IPO Closing Date are included in the Partnership’s financial statements.

Other Liabilities Assumed. The historical book value and related activity of other liabilities assumed including natural gas imbalances received from the Predecessor was determined by using the specific obligations related to the properties listed in the October 2011 Purchase Agreement. The balances of these obligations as of the effective date of the October 2011 Purchase Agreement and all related previous activity dating back to the IPO Closing Date are included in the Partnership’s financial statements.

Oil and Natural Gas Revenues and Expenses. Oil and natural gas revenues and expenses related to the October 2011 Transferred Properties and the December 2012 Transferred Properties were determined based on operating activity for the specific properties listed in the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. All oil and natural gas revenues and expense activity are included in the Partnership’s financial statements dating back to the IPO Closing Date.

General and Administrative Expenses. The general and administrative expense attributable to the October 2011Transferred Properties and the December 2012 Transferred Properties was determined by the ratio of production for the October 2011 Transferred Properties and the December 2012 Transferred Properties to the total Predecessor’s production. This ratio was applied to the specific properties listed in the October 2011 Purchase Agreement and the December 2012 Purchase Agreement. All general and administrative expense identified is included in the Partnership’s financial statements dating back to the IPO Closing Date.

Business Combinations

We account for all business combinations using the purchase method, in accordance with GAAP. Under the purchase method of accounting, the purchase price is based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets acquired and liabilities assumed are measured at their fair values. The difference between the fair value of assets acquired and liabilities assumed and the purchase price of the entity, if any, is recorded as either goodwill or a bargain purchase gain. The Partnership has not recognized any goodwill from business combinations.

Oil and Natural Gas Reserve Quantities

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. Our independent reserve engineers also adhere to the SEC definitions when preparing their reserve reports.

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Investments

Investments consist of debt and equity securities, all of which are classified as available-for-sale and stated at fair value on our consolidated balance sheet. Accordingly, unrecognized changes in fair value and the related deferred tax effect are excluded from earnings and reported as a separate component within our consolidated statement of other comprehensive income. Changes in fair value of securities sold are computed based on the specific identification of the securities sold and reclassified from other comprehensive income into earnings in the period sold.

Pensions and Other Postretirement Benefits

We recognize the overfunded or underfunded status of the pension and postretirement benefit plans as either assets or liabilities on our consolidated balance sheet. A plan’s funded status is the difference between the fair value of the plan assets and the plan’s benefit obligation. The plan’s benefit obligation is based on estimates using management’s best estimate and judgments which includes independent actuarial service assumptions to determine the plan obligation. We record the plan’s cost and income – unrecognized losses and gains, unrecognized prior service costs and credits and any transition obligations, if any – in our statement of other comprehensive income until they are amortized into earnings as a component of benefit costs.

Asset Retirement Obligations

We have significant obligations to plug and abandon oil, natural gas and saltwater disposal wells and related equipment at the end of oil and natural gas production or saltwater disposal operations. We incur these liabilities upon acquiring or drilling a well. GAAP requires entities to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depleted as a component of the full cost pool. The fair values of additions to the ARO liability are estimated using present value techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) inflation factors; and (iv) a credit-adjusted risk free rate. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance. Upon settlement of liabilities related to our oil and natural gas properties, we adjust the full cost pool to the extent the actual costs differ from the recorded liability. Upon settlement of liabilities related to our other property, plant and equipment, we record a gain or loss in earnings to the extent the actual costs differ from the recorded liability. See Note 8 – Asset Retirement Obligation.

Derivatives

We monitor our exposure to various business risks, including commodity price risks and interest rate risks, and use derivatives to manage the impact of certain of these risks. Our policies do not permit the use of derivatives for speculative purposes. We use commodity derivatives for the purpose of mitigating risk resulting from fluctuations in the market price of oil and natural gas and interest rate derivatives for the purpose of mitigating risk resulting from fluctuations in interest rates.

We have elected not to designate our derivatives as hedging instruments. Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Gains and losses on derivatives are reported as nonoperating income or expense on the statements of operations in “Gain (loss) on commodity derivative contracts, net.” Gains and losses on derivatives include the cash settlement of derivative contracts and the non-cash change in fair value of the derivative instruments. See Note 6 – Fair Value Measurements and Note 7 – Derivative Activities.

Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. The credit worthiness of the counterparties is subject to continual review. We believe the risk of nonperformance by our counterparties is low. Full performance is anticipated, and we have no past-due balances from our counterparties. In addition, although we have the ability to elect to enter into netting agreements under our derivative instruments with certain of our counterparties, we have properly presented all asset and liability positions without netting. See Note 7 – Derivative Activities.

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Deferred Financing Costs

Costs incurred in connection with the execution or modification of our debt arrangements are capitalized and charged to interest expense over the term of the debt instrument. The net capitalized costs associated with our revolver are adjusted for downward revisions to the borrowing base.

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt. The carrying amounts of our financial instruments other than derivatives and long-term debt approximate fair value because of the short-term nature of the items. Derivatives are recorded at fair value. The carrying value of our debt under the Revolving Credit Facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. The Senior Notes are recorded at historical cost. See Note 6 – Fair Value Measurements.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. A process is used to determine when expenses should be recorded for these contingencies and the estimate of reasonable amounts for the accrual. We closely monitor known and potential legal, environmental and other contingencies, and periodically determine when we should record losses for these items based on information available. Based on management’s assessment, no contingent liabilities have been recorded by the Partnership as of December 31, 2013 or 2012, with the exception of an environmental liability acquired in the Prize Acquisition. See Note 11 – Commitments and Contingencies for further details.

Concentrations of Credit and Market Risk

Credit risk

Financial instruments which potentially subject us to credit risk consist principally of temporary cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at time, may exceed the federally insured limits. We have not experienced any significant losses from such investments. We attempt to limit the amount of credit exposure to any one financial institution or company. Procedures that may be used to manage credit exposure include credit approvals, credit limits and terms, letters of credit, prepayments and rights of offset.

Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry. We have not experienced any material credit losses on such sales in the past. See Note 17 – Significant Customers for further details.

Market Risk

Our activities primarily consist of acquiring, owning, enhancing and producing oil and gas properties. The future results of our operations, cash flows and financial condition may be affected by changes in the market price of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond our control, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment and, other regional and political events, none of which can be predicted with certainty.

Preferred Units

Our Preferred Units are convertible by the preferred unitholders and us under certain circumstances into common units. These conversion features result in settlement in common units and the option to convert is clearly and closely related to the units. These units are also not redeemable in cash. As such, we have classified the Preferred Units as permanent equity.

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The Preferred Units have a liquidation preference equal to $21.00 per unit outstanding and any cumulative distributions in arrears.

We recorded the Preferred Units at their fair value of $21.27 per unit or $354.5 million in partners’ capital. Because the Preferred Units include stated distribution rates which increase over time, from a rate considered below market, we will amortize an incremental amount which together with the stated rate for the period results in a constant distribution rate in accordance with GAAP. We determined the present value of the incremental distributions of $46.2 million will be amortized over the period preceding the perpetual dividend rate using an effective interest rate of 8.1%. The amortization will increase the carrying value of the Preferred Units with an offsetting noncash distribution reducing the general partner’s and limited partners’ capital accounts on a pro rata basis. These distributions will be included in preferred distributions in our calculation of net income applicable to limited partners and basic and diluted net income per unit.

There was no beneficial conversion feature as our common units were trading below the $21.27 per unit fair value of the Preferred Units as of December 31, 2013.

Revenue Recognition

Revenues from oil, natural gas and NGL sales are recognized upon delivery and passage of title when evidence of arrangement exists and collectability is reasonably assured. Gas imbalances are recognized using the sales method, net of any royalty interests or other profit interests in the produced product. Revenues from natural gas production may result in more or less than our pro rata share of production from certain wells. Under the sales method for natural gas sales and natural gas imbalances, when our sales volumes exceed our entitled share and the overproduced balance exceeds our share of remaining estimated proved natural gas reserves for a given property, we record a liability. See Note 16 – Accrued and Other Liabilities.

General and Administrative Expenses

The Partnership shares general and administrative expenses with other affiliates who also receive management and accounting services from QRM under a Services Agreement, as defined in Note 19 – Related Party Transactions.

Through 2012, our general and administrative expenses, for any quarter therein, were comprised of:

•

Direct general and administrative expenses incurred by QRM on our behalf (“Direct G&A”) and charged to us;

•

Administrative service fees, as discussed in Note 19 – Related Party Transactions, payable by us to QRM during the term of the Services Agreement; and

•

Our share of allocable indirect general and administrative expenses incurred by QRM on behalf of the affiliates for which it provides management services which are in excess of the administrative services fee charged to us (“Allocated G&A”).

We were not required to reimburse QRM for Allocated G&A in excess of administrative service fees during the initial term of the Services Agreement through 2012. Therefore, these allocated expenses were recorded as capital contributions from the Fund in our Consolidated Statement of Partner’s Capital. This allocation methodology, based on relative production volumes, has been reviewed and approved by QRE GP’s board of directors, including independent directors, as a reasonable method of sharing these expenses with 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.

After December 31, 2012, the Partnership was required to reimburse QRM for its share of allocable general and administrative expenses based on the estimated use of such services. 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 G&A 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

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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.

Management Incentive Fee

Under our partnership agreement, as amended, for each quarter for which we pay distributions that are equal or greater than 115% of our minimum quarterly distribution (which we refer to as our “Target Distribution”), QRE GP will be entitled to a quarterly management incentive fee, payable in cash, equal to 0.25% of a management incentive fee base. With the expiration of the subordination period on December 22, 2012 and having received three full quarters of management incentive fees, QRE GP became eligible to convert up to 80% of its fourth quarter 2012 management incentive fee for 6,133,558 Class B units. On February 22, 2013, QRE GP elected to convert 80% of their fourth quarter management incentive fee and, on March 4, 2013, received 6,133,558 Class B units. The calculation of the management incentive fee and conversion and the current year expense is discussed further in Note 19 – Related Party Transactions.

Income Taxes

We are treated as a partnership for federal income tax purposes except for the income and losses generated from our controlling interest in the ETSWDC. Our federal taxable income and losses are primarily reported on the income tax returns of the partners. We are also subject to the Texas Margin tax which is derived from our taxable income apportioned to Texas. Refer to Note 18 – Income Taxes for further details of our tax accounts.

We use the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to the taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities from a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

We performed evaluations as of December 31, 2013 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.

Net Income (Loss) per Limited Partner Unit

Net income (loss) per limited partner unit is determined by dividing net income available to the limited partners, after deducting distributions to preferred unitholders, the general partner’s 0.1% interest in net income, and net income attributable to non-controlling interest, by the weighted average number of limited partner units outstanding. Income from the October 2011 Transferred Properties and the December 2012 Transferred Properties is excluded from the calculation of net income (loss) per limited partner as the income relates to the Predecessor operations. The Preferred Units and the management incentive fee, to the extent eligible for conversion into Class B units, are contingently convertible and will be included in the denominator for diluted income per unit unless they are anti-dilutive. See Note 13 – Net Income (Loss) Per Limited Partner Unit.

Business Segment Reporting

We operate in one reportable segment engaged in the development, exploitation and production of oil and natural gas properties. All of our operations are located in the United States.

Equity-Based Compensation

We have granted equity-classified restricted unit awards which we account for at fair value. Restricted unit awards, net of estimated forfeitures, are expensed over the requisite service period. As each award vests, an adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the vested awards. For equity-based awards that contain service conditions, compensation cost is recorded using the straight-line method. For equity-based performance awards that contain a market condition,

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we estimate the grant date fair value based on the fair value derived from the Monte Carlo model and record the expense using the straight-line method over the performance period.

During 2013, 2012 and 2011 we have granted awards to employees and directors of QRM who performed services for us. We record these compensation costs as direct general and administrative expenses. See Note 15 – Equity Based Compensation.

Recent Accounting Pronouncements

Effective with the acquisition of ETSWDC in August 2013, we adopted ASU 2013-02, Comprehensive Income: Reporting Amounts Reclassified Out of Accumulated Other Comprehensive Income (AOCI). The ASU requires aggregated disclosures of amounts reclassified out of AOCI as well as a presentation of changes in AOCI balances by component. The changes in AOCI by component, including amounts reclassified out of AOCI in their entirety are presented in the consolidated statement of comprehensive income. This update did not impact our balance sheet, results of operations or cash flows.

In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The ASU clarifies that ASU 2011-11, discussed above, ordinary trade receivables and receivables are not in the scope of ASU 2011-11. This ASU issuance does not change our evaluation of ASU 2011-11 on our disclosures as noted below.

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 both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to the master netting arrangement. This scope does not 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.

NOTE 3 — OIL AND GAS ASSETS

Costs Excluded From Amortization

The following is a summary of our oil and gas properties not subject to amortization:


	December 31, 2013		December 31, 2012
Acquisition of unevaluated properties:
Incurred in 2013	$	—	$	—
Incurred in 2012		4,320		11,500
Incurred in 2011 and prior		—		—

Total oil and gas properties not subject to amortization	$	4,320	$	11,500

The 2012 total costs excluded from the amortization base were obtained in the Prize Acquisition and the 2012 East Texas Acquisition. We believe that our evaluation activities related to all of our properties not subject to amortization will be completed within five years.

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NOTE 4 — ACQUISITIONS

Third Party Acquisitions

2013 East Texas Oil Field Acquisition

On August 6, 2013, we closed the acquisition of primarily oil properties located in East Texas (the “2013 East Texas Acquisition”) from a private seller for $107.8 million cash, subject to customary purchase price adjustments, using funds drawn on our revolving credit facility. The acquired properties (the “2013 East Texas Properties”) had estimated proved reserves of 5.9 MMBoe as of the date of the acquisition utilizing SEC case pricing. The acquisition had an effective date of June 1, 2013. The costs associated with the 2013 East Texas Acquisition of $0.4 million are recorded in “Acquisition and transaction costs” on our consolidated statements of operations for the year ended December 31, 2013. In connection with the 2013 East Texas Acquisition, we assumed an estimated environmental liability of $0.5 million. Refer to Note 11 – Commitments and Contingencies for further details. Since the closing date, revenues of $60 million and production expenses of $15.2 million related to the operation of the 2013 East Texas Properties are included in our consolidated statements of operations for year ended December 31, 2013.

In connection with the 2013 East Texas Acquisition, we also acquired a 32% interest in ETSWDC giving us control of ETSWDC as we previously owned 24%. During the fourth quarter 2013 we acquired an additional 3% from another seller giving us a 59% ownership interest as of December 31, 2013. As of the closing date of the 2013 East Texas Acquisition, we have a controlling interest in the ETSWDC and have consolidated ETSWDC into our consolidated financial statements. In addition, our previous ownership in ETSWDC was remeasured to fair value on the acquisition date resulting in a gain of $1.3 million recognized in “Other income (expense)” in our consolidated statements of operations.

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

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


Oil and gas properties	$	105,141
Investment in ETSWDC		9,576
Asset retirement obligation		(6,069	)
Other current liabilities		(884	)

Net assets acquired	$	107,764

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


Assets acquired and liabilities assumed:
Current assets (1)	$	7,858
Property, plant and equipment, net		13,103
Other long term assets		16,215

Total assets		37,176

Liabilities:
Current liabilities		(1,761	)
Asset retirement obligation		(4,607	)
Pension and postretirement benefits		(12,039	)

Total liabilities		(18,407	)

Fair value of saltwater disposal company		18,769
Less: remeasurement of previously held interest		(3,237	)
Less: fair value of noncontrolling interest		(5,956	)

Fair value of ETSWDC acquired by QR Energy, LP	$	9,576

⁽¹⁾	Includes $3.5 million of cash and cash equivalents.

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

Other 2013 Acquisitions

During the fourth quarter of 2013, we also closed various small acquisitions of oil and gas properties with an aggregate purchase price of $22.6 million in cash, subject to customary purchase price adjustments, using funds drawn from our revolving credit facility.

2012 East Texas Oil Field Acquisition

On December 4, 2012 we closed the East Texas Oil Field Acquisition (the “2012 East Texas Acquisition”). We acquired the East Texas Oil Field Properties (the “2012 East Texas Properties”) for $214.3 million in cash after customary purchase price adjustments. The acquired properties had estimated proved reserves of 10.8 MMBoe as of December 31, 2011 utilizing SEC case pricing. The acquisition had an effective date of November 1, 2012. The costs associated with the 2012 East Texas Acquisition of $0.3 million are recorded in “Acquisition and transaction costs” in the consolidated statement of operations for the year ended December 31, 2012. The 2012 East Texas Acquisition qualified as a business combination and was accounted for under the purchase method of accounting. The fair value measurements of the oil and gas properties and asset retirement obligations were measured using valuation techniques and unobservable inputs that convert future cash flows to a single discounted amount.

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


Oil and gas properties
Evaluated (1)	$	218,039
Unevaluated		5,400
Other Assets		1,900
Asset retirement obligation		(9,843	)
Other current liabilities		(1,190	)

Net assets acquired	$	214,306

⁽¹⁾	Includes receivable from seller for customary purchase price adjustments recorded in prepaid and other current assets as of December 31, 2012, which was received during 2013.

Prize Acquisition

On April 20, 2012 we closed the Prize Acquisition. We acquired predominantly low decline, long life oil properties, almost all of which are located in the Ark-La-Tex area, for $225.1 million in cash after customary purchase price adjustments. The acquired properties had estimated proved reserves as of December 31, 2011 utilizing SEC case pricing of 13.3 MMBoe. The acquisition had an effective date of January 1, 2012. The costs associated with the Prize Acquisition of $1.1 million are recorded in “Acquisition and transaction costs” in the consolidated statement of operations for the year ended December 31, 2012. In conjunction with the Prize Acquisition, we assumed an estimated environmental liability of $1.9 million. Refer to Note 11 – Commitments and Contingencies for further details. Since the closing date, revenues of $24.6 million and operating expenses of $8.3 million related to the operation of the Prize properties are included in the consolidated statements of operations for the year ended December 31, 2012. The Prize Acquisition qualified as a business combination and was accounted for under the purchase method of accounting. The fair value measurements of the oil and gas properties and asset retirement obligations were measured using valuation techniques and unobservable inputs that convert future cash flows to a single discounted amount.

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


Oil and gas properties
Evaluated	$	226,670
Unevaluated		6,100
Asset retirement obligation		(4,738	)
Environmental liability		(1,891	)
Other current liabilities		(993	)

Net assets acquired	$	225,148

Pro forma Financial Data

The following unaudited pro forma income statement information for years ended December 31, 2013 and 2012 assumes the 2013 East Texas Acquisition had occurred on January 1, 2012, and 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.


	Year Ended (Unaudited)
	December 31, 2013		December 31, 2012
	Pro Forma		Pro Forma
Total revenues	$	485,284	$	476,345
Operating income	$	115,104	$	104,327
Net income attributable to QR Energy, LP	$	66,068	$	107,238
Net income per unit:
Common unitholders’ (basic)	$	0.34	$	0.75
Common unitholders’ (diluted)	$	0.34	$	0.73

Subordinated units (basic and diluted)	$	—	$	0.78

Affiliated Acquisitions

On December 28, 2012, we completed our acquisition of the December 2012 Transferred Properties from the Fund in exchange of $28.6 million in cash, after customary purchase price adjustments, and the assumption of $115 million in debt. The net assets were recorded by the Partnership using historical book value of the Fund as the acquisition is a transaction between entities under common control. Our historical financial statements were revised to include the results attributable to the December 2012 Transferred Properties as if we owned the properties for all periods presented in our consolidated financial statements. See Note 1 – Organization and Operations for further disclosures regarding this transaction. See Note 2 – Summary of Significant Accounting Policies for further discussion regarding the accounting policies for transactions between entities under common control.


Oil and gas properties
Evaluated	$	141,315
Accumulated depreciation, depletion, and amortization		(45,416	)
Other assets (1)		10,732
Derivative instruments, net		(2,948	)
Long-term debt		(115,000	)
Asset retirement obligation		(34,261	)

Book value of net assets		(45,578	)
Purchase price adjustment		5,270

Net assets contributed by the Predecessor (2)	$	(40,308	)

⁽¹⁾	Represents a reclamation deposit in escrow as security for abandonment and redemption obligations.

⁽²⁾

The net assets contributed to us include the historical book value of the Predecessor as prescribed by our accounting policy for transactions between entities under common control in Note 2 – Summary of Significant Accounting Policies and a $5.3 million purchase price adjustment related to novated derivatives unwound by the Partnership.

F-19

Effective October 1, 2011, we completed our acquisition of the October 2011 Transferred Properties from the Fund in exchange for 16,666,667 Class C Convertible Preferred Units and the assumption of $227 million in debt. The net assets were recorded by the Partnership using historical book value of the Fund as the acquisition is a transaction between entities under common control. See Note 1 – Organization and Operations for further disclosures regarding this transaction.


Oil and gas properties, net	$	441,207
Gas processing equipment, net		251
Derivative instrument asset, net		64,671
Deferred tax asset		205
Long-term debt		(227,000	)
Asset retirement obligation		(26,294	)
Natural gas imbalance		(3,709	)

Book value of net assets		249,331
Purchase price adjustments		2,715

Net assets contributed by the Predecessor (1)	$	252,046

⁽¹⁾

The net assets contributed to us include the historical book value of the Predecessor as prescribed by our accounting policy for transactions between entities under common control in Note 2 – Summary of Significant Accounting Policies and a $2.7 million purchase price adjustment for natural gas imbalances in accordance with the purchase and sale agreement.

NOTE 5 — INVESTMENTS

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

As of December 31, 2012, we had no available for sale investments outstanding. As of December 31, 2013, we had the following available for sale investments outstanding:


	Cost Basis		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value

Available-for-sale securities:
Equities	$	3,647	$	361	$	41	$	3,967
Mutual funds		11,339		320		20		11,639
Exchange traded funds		2,924		217		1		3,140

Total for available-for-sale securities	$	17,910	$	898	$	62	$	18,746

During the year ended December 31, 2013 we received $8.6 million in proceeds from the sale of available-for-sale securities with a realized loss of less than $0.1 million.

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

NOTE 6 — FAIR VALUE MEASUREMENTS

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

F-20


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

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

Level 3 -		Defined as unobservable inputs for use when little or no market data exists, therefore requiring amenity to develop its own assumptions for the asset or liability.

Commodity Derivative Instruments – The fair value of the commodity derivative instruments are estimated using a combined income and market valuation methodology based upon forward commodity prices and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. 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 are estimated using a combined income and market valuation methodology based upon forward interest rates and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. We validate the data provided by independent pricing services by comparing such pricing against other third party pricing data.

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

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


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

	$	108,362	$	18,746	$	89,616	$	—


Liabilities from commodity derivative instruments	$	7,093	$	—	$	7,093	$	—
Liabilities from interest rate derivative instruments		10,391		—		10,391		—

	$	17,484	$	—	$	17,484	$	—


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	$	—

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 credit facility debt depends primarily on the current active market LIBOR. The carrying value of our credit facility debt as of December 31, 2013 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.

F-21

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 December 31, 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 7 – Derivative Activities for further information on the derivative premiums.

Senior Notes – The fair value of the Senior Notes is measured based on inputs from quoted, unadjusted prices from over-the-counter markets for debt instruments. If the Senior Notes had been measured at fair value, we would classify them as Level 1 under the fair value hierarchy. The fair value of the Senior Notes as of December 31, 2013 was $312.2 million.

There have been no transfers between levels within the fair value measurement hierarchy during the year ended December 31, 2013.

NOTE 7 — 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. All of our derivative contracts reflected in the consolidated balance sheet have been adjusted for nonperformance.

Commodity Derivatives

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

During the year ended December 31, 2013, we entered into new oil swap contracts and basis swap contracts with settlement dates ranging from 2013 through 2017. All of the new contracts were entered into with counterparties under our revolving credit facility. Additionally, in the fourth quarter of 2013, we converted WTI swaps to LLS swaps.

During the year ended December 31, 2012, we terminated certain oil derivative contracts that were novated to us in connection with the December 2012 Transferred Properties which were scheduled to expire at various times in 2013 and recorded $5.3 million as an adjustment to the purchase price.

The deferred premiums associated with certain of our oil and natural gas derivative instruments are $5.0 million and $4.9 million and are classified as other non-current liabilities on the consolidated balance sheets as of December 31, 2013 and 2012. These deferred premiums will be paid to the counterparty with each monthly settlement (January 2015 – December 2017) and recognized as an adjustment of Gain (loss) on commodity derivative contracts, net.

F-22

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 December 31, 2013, the notional volumes of our commodity derivative contracts were:


Commodity	Index	2014			2015			2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		6,715			7,356			6,293		5,547
Average price ($/Bbls)		$	95.30		$	93.74		$	90.03	$	86.23
Hedged Volume (Bbls/d)	LLS		3,000			—			—		—
Average price ($/Bbls)		$	99.62			—			—		—
Basis
Hedged Volume (Bbls/d)	WTS/WTI		2,400			—			—		—
Average price ($/Bbls)		$	(2.10	)		—			—		—
Collars
Hedged Volume (Bbls/d)	WTI		425			1,025			1,500		—
Average floor price ($/Bbls)		$	90.00		$	90.00		$	80.00		—
Average ceiling price ($/Bbls)		$	106.50		$	110.00		$	102.00		—

Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		26,622			7,191			11,350		10,445
Average price ($/MMBtu)		$	6.18		$	5.34		$	4.27	$	4.47
Basis Swaps (1)
Hedged Volume (MMBtu/d)	Henry Hub		17,066			14,400			—		—
Average price ($/MMBtu)		$	(0.19	)	$	(0.19	)		—		—
Collars
Hedged Volume (MMBtu/d)	Henry Hub		4,966			18,000			630		595
Average floor price ($/MMBtu)		$	5.74		$	5.00		$	4.00	$	4.00
Average ceiling price ($/MMBtu)		$	7.51		$	7.48		$	5.55	$	6.15
Puts
Hedged Volume (MMBtu/d)	Henry Hub		—			420			11,350		10,445
Average price ($/MMBtu)			—		$	4.00		$	4.00	$	4.00

⁽¹⁾	Our natural gas basis swaps are used to hedge the differential between Henry Hub and various points.

Interest Rate Derivatives

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

During 2013, we entered into $410 million of new interest rate swaps with termination dates through 2016. The new contracts were entered into with various financial institutions.

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

Credit Risk

By using derivative instruments to hedge exposures to changes in commodity prices and interest rates, when applicable, we are exposed to credit risk. Credit risk is the failure of a counterparty to perform under the terms of the derivative contract. When the fair value of a derivative is in an asset position, the counterparty owes the Partnership, which creates credit risk. We do not receive collateral from our counterparties. The maximum amount of loss to credit risk, based on the gross fair value of our derivative contracts, is $1.1 million as of December 31, 2013.

F-23

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:


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

Commodity contracts	$	89,616	$	7,093	$	122,143	$	13,484
Interest rate contracts		—		10,391		—		12,236

	$	89,616	$	17,484	$	122,143	$	25,720

Commodity
Current	$	27,485	$	5,651	$	45,522	$	4,130
Noncurrent		62,131		1,442		76,621		9,354

	$	89,616	$	7,093	$	122,143	$	13,484

Interest
Current	$	—	$	5,582	$	—	$	4,597
Noncurrent		—		4,809		—		7,639

	$	—	$	10,391	$	—	$	12,236


Total Derivatives
Current	$	27,485	$	11,233	$	45,522	$	8,727
Noncurrent		62,131		6,251		76,621		16,993

	$	89,616	$	17,484	$	122,143	$	25,720

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


	December 31, 2013						December 31, 2012
	Asset			Liability			Asset			Liability
	Derivatives			Derivatives			Derivatives			Derivatives
Gross derivatives	$	89,616		$	17,484		$	122,143		$	25,720
Netting		(2,960	)		(2,960	)		(11,594	)		(11,594	)

Net derivatives	$	86,656		$	14,524		$	110,549		$	14,126

The following table presents the impact of derivatives and their location within the consolidated statements of operations for the indicated periods:


	Year Ended
	December 31,			December 31,			December 31,
	2013			2012			2011
Total gains (losses):
Commodity contracts (1)	$	(1,217	)	$	53,071		$	47,860
Interest rate contracts (2)		(2,913	)		(10,221	)		(29,426	)

Total	$	(4,130	)	$	42,850		$	18,434

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

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

NOTE 8 — ASSET RETIREMENT OBLIGATIONS

The total undiscounted amount of future cash flows to settle our asset retirement obligations is estimated to be $352.5 million and $275.0 million at December 31, 2013 and 2012. Payments to settle asset retirement obligations occur over the lives of the gas properties and other plant, property and equipment, estimated to be from less than one year to 45 years.

F-24

Changes in the asset retirement obligations are presented in the following table:


	Year Ended
	December 31, 2013			December 31, 2012
Beginning of period	$	126,991		$	92,561
Assumed in acquisitions		13,409			14,581
Revisions to previous estimates (1)		12,911			17,278
Liabilities incurred		360			1,185
Liabilities settled		(5,806	)		(4,262	)
Accretion expense		7,456			5,648

End of period	$	155,321		$	126,991
Less: Current portion of asset retirement obligations		4,310			1,426

Asset retirement obligations - non current	$	151,011		$	125,565

⁽¹⁾	In 2013 and 2012, we recorded an upward revision to previous estimates for our asset retirement obligations primarily due to changes in the estimated abandonment dates.

NOTE 9 — PENSIONS AND POSTRETIREMENT BENEFITS

The ETSWDC sponsors a noncontributory defined benefit pension plan and a contributory other post-retirement benefit plan (collectively, the “Plans”) covering substantially all ETSWDC employees who were employed prior to March 31, 2008. Subsequent to March 31, 2008, the Plans were closed to new employees. The tables below set forth the benefit obligation, fair value of plan assets, and the funded status of the Plans; amounts recognized in the Partnership’s financial statements; and the principal weighted average assumptions used.

Obligation and Funded Status

The Plans have accumulated benefit obligations in excess of plan assets as shown in the table below:


	December 31, 2013
	Pension Benefits		Postretirement Benefits
Projected benefit obligation	$	23,592	$	3,922
Accumulated benefit obligation		22,724		3,922
Fair value of plan assets		20,466		1,438

The change in the combined projected benefit obligation of the Plans and the change in the assets at fair value are as follows:


	Year Ended December 31, 2013
	Pension Benefits			Postretirement Benefits
Change in Benefit Obligation
Benefit obligation at beginning of year	$	—		$	—
2013 East Texas Oil Field Acquisition		24,697			8,326
Service cost		135			29
Interest cost		429			145
Plan participant contributions		—			25
Actuarial (gain) loss		(1,136	)		(4,364	)
Benefits paid		(533	)		(239	)

Benefit obligation at end of year		23,592			3,922

Change in Plan Assets
Fair value of plan assets at beginning of year		—			—
2013 East Texas Oil Field Acquisition		19,518			1,466
Actual return on plan assets		1,127			91
Employer contributions		354			95
Plan participant contributions		—			25
Benefits paid		(533	)		(239	)

Fair value of plan assets at end of year		20,466			1,438

Under funded status at end of year	$	(3,126	)	$	(2,484	)

F-25

Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet consist of the following:


	Pension Benefits				Postretirement Benefits
	Year Ended				Year Ended
	December 31,				December 31,
	2013		2012		2013		2012
Current liabilities	$	—	$	—	$	—	$	—
Long-term liabilities		3,126		—		2,484		—

	$	3,126	$	—	$	2,484	$	—

Components of Net Periodic Benefit Cost and Other Comprehensive Income

Net periodic benefit costs recognized in the consolidated statements of operations consist of the following for the indicated periods:


	Pension Benefits					Postretirement Benefits
	Year Ended					Year Ended
	December 31,					December 31,
	2013			2012		2013			2012
Service cost	$	135		$	—	$	29		$	—
Interest cost		429			—		145			—
Expected return on plan assets		(529	)		—		(35	)		—

Net periodic postretirement benefit costs	$	35		$	—	$	139			—

Amounts recognized in accumulated other comprehensive income consist of the following:


	Pension Benefits				Postretirement Benefits
	Year Ended				Year Ended
	December 31,				December 31,
	2013		2012		2013			2012
Prior service cost	$	—	$	—	$	—		$	—
Net actuarial gain:
Liability gain due to assumption change		735		—		(2,189	)		—
Liability gain due to participant experience		401		—		(2,175	)		—
Asset return gain		598		—		(56	)		—

Net actuarial gain		1,734		—		(4,420	)		—

Total	$	1,734	$	—	$	(4,420	)	$	—

Estimated Future Benefit Payments

The following estimated benefit payments under the Plans, which reflect expected future service, as appropriate, are expected to be paid as follows:


	Pension Benefits		Other Benefits
2014	$	1,430	$	180
2015		1,530		240
2016		1,530		230
2017		1,590		240
2018		1,620		250
2019-2023		8,390		1,260

The ETSWDC expects to contribute approximately $1.1 million and $0.2 million to the pension and other postretirement plan, respectively, in 2014.

F-26

Assumptions

Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:


	Pension Benefits					Postretirement Benefits
	Year Ended					Year Ended
	December 31,					December 31,
	2013			2012		2013			2012
Discount rate		4.50	%		—		4.50	%		—
Rate of compensation increase		3.00	%		—		N/A			N/A
Health care cost trend rate:
Pre - 65 rate		N/A			N/A		7.00	%		—
Post - 65 rate		N/A			N/A		5.00	%		—
Expected long-term rates of return on plan assets		6.75	%		—		6.75	%		—

Assumptions used to determine net periodic benefit costs are as follows:


	Pension Benefits					Postretirement Benefits
	Year Ended					Year Ended
	December 31,					December 31,
	2013			2012		2013			2012
Discount rate		4.25	%		—		4.25	%		—
Expected long-term return on plan assets		6.75	%		—		5.75	%		—
Rate of compensation increase		3.50	%		—		N/A			—

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:


	Postretirement Benefits
	1-Percentage-		1-Percentage-
	Point Increase		Point Decrease
Effect on total service and interest cost	$	26	$	22
Effect on postretirement benefit obligation		417		353

The following table presents the fair values of our pension plan assets by level within the fair value hierarchy, as of December 31, 2013


	December 31, 2013
	Level 1		Level 2		Level 3		Total
Equity securities:
Pooled Funds (1)	$	—	$	9,239	$	—	$	9,239
Fixed income securities:
Pooled Funds (2)		—		11,227		—		11,227

Total investments, at fair value	$	—	$	20,466	$	—	$	20,466

⁽¹⁾	Investments consist primarily of pooled separate accounts which focus on long-term growth of capital through U.S. and international securities.

⁽²⁾	Investments consist primarily of pooled separate accounts which focus on long-term growth of capital and preservation of equity though U.S. and international securities.

The following table presents the fair values of our postretirement benefit plan assets by level within the fair value hierarchy, as of December 31, 2013.


	December 31, 2013
	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	333	$	—	$	—	$	333
Equity securities:
Mutual Funds (1)		370		—		—		370
Fixed income securities:
Corporate bonds		735		—		—		735

Total investments, at fair value	$	1,438	$	—	$	—	$	1,438

⁽¹⁾	Investments consist primarily of mutual funds which focus on growth of capital and income maximization.

F-27

Plan Investment Policies and Strategies

The investment policies for the Plans reflect the funded status of the Plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the Plans’ investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation.

Historical performance and future expectations suggest that common stocks will provide higher total investment returns than fixed income securities over a long-term investment horizon. Short-term investments are utilized for pension payments, expenses, and other liquidity needs. As such, the Plan’s targeted asset allocation is comprised of approximately 50 percent equity securities and approximately 50 percent high-yield bonds and other fixed income securities but may be adjusted to better match the plan’s liabilities over time as the funded ratio (as defined by the investment policy) changes.

The Plans’ assets are managed by a third-party investment manager. The investment manager is limited to pursuing the investment strategies regarding asset mix and purchases and sales of securities within the parameters defined in the investment policy guidelines and investment management agreement. Investment performance and risk is measured and monitored on an ongoing basis through annual investment meetings and periodic cash flow studies.

Expected long-term return on plan assets

The overall expected long-term return on plan assets assumption is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account the Plans’ asset allocations to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.

Fair Value Measurements

Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 2013.

Cash and cash equivalents – Cash and cash equivalents include cash on deposit which are valued using a market approach and are considered Level 1.

Mutual funds – Investments in mutual funds are valued using a market approach. The shares or units held are traded on the public exchanges and such prices are Level 1 inputs.

Pooled funds – Investments in pooled funds are valued using a market approach at the net asset value of units held, but investment opportunities in such funds are limited to institutional investors on the behalf of defined benefit plans. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2.

Corporate bonds – Investments in corporate bonds are valued using a market approach. Bonds are valued at the closing price reported on the active market on which the securities are traded and are considered Level 1.

F-28

NOTE 10 — LONG-TERM DEBT

Consolidated debt obligations consisted of the following as of the dates indicated:


	Year Ended
	December 31,
	2013		2012
Senior secured revolving credit facility	$	615,000	$	470,000
9.25% Senior Notes due 2020 (1)		296,593		296,076

	$	911,593	$	766,076


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

⁽¹⁾	The amount is net of unamortized discount of $3.4 and $3.9 million as of December 31, 2013 and 2012, respectively.

⁽²⁾	These letters of credit relate to a reclamation deposit requirement. Refer to Note 11 – Commitments and Contingencies for details.

Revolving Credit Facility

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

As of December 31, 2013, we had a $950 million borrowing base, $615.0 million of borrowings outstanding and $23.5 million of letters of credit issued resulting in $311.5 million of borrowing availability. During 2013, our weighted-average interest rate paid on our variable debt obligation was 3.6%, excluding the impact of hedges. At December 31, 2013, our weighted average-interest on the variable debt obligation was 2.2%, excluding the potential impact of hedges.

Effective March 2, 2014, we entered into the sixth amendment to the Credit Agreement, which permits the GP Buyout Transaction. See Note 22 – Subsequent Events.

On October 15, 2013, our revolving credit facility borrowing base increased to $950 million as a result of our semi-annual borrowing base redetermination.

Effective August 6, 2013, we entered into the fifth amendment to the Credit Agreement, which provides for the exclusion of ETSWDC as a guarantor of our credit facility.

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

In July 2012, our borrowing base was reduced by $75 million to $655 million from $730 million as result of the issuance of the Senior Notes on July 30, 2012. In connection with the reduction of the borrowing base, we wrote-off approximately $0.7 million of deferred loan costs associated with the Credit Agreement. On October 30, 2012, as part of our semi-annual borrowing base redetermination, our borrowing base returned to $730 million.

During 2012, we entered into the second and third amendments to the Credit Agreement that, among other things, (i) provided for additional derivative contracts to cover production of proved reserves to be acquired, (ii) increased our credit facility from $750 million to $1.5 billion, increasing our borrowing base from $630 million to $730 million effective April 2012 and (iii) extended the maturity date from December 22, 2015 to April 20, 2017.

As of December 31, 2013, the Credit Agreement provides for a five-year, $1.5 billion revolving credit facility maturing on April 20, 2017, with a borrowing base of approximately $950 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

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prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum.

The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and also requires us to provide audited financial statements within 90 days of year end and quarterly unaudited financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of December 31, 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 our 9.25% Senior Notes, due 2020 (the “Senior Notes”). The Senior Notes were issued at 98.62% of par. We received approximately $291.2 million of cash proceeds, net of the discount and underwriting fees, with total net proceeds of approximately $290.2 million, after $1.0 million of offering costs. We used the net proceeds from the sale of the Senior Notes to repay borrowings outstanding under our credit facility. In 2012, we filed and completed a registration statement with the SEC to allow holders of the Senior Notes to exchange for registered Senior Notes that have substantially identical terms as the Senior Notes. The registration statement was declared effective on September 20, 2012 and the exchange offer was completed on November 7, 2012. We will have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture governing the Senior Notes. 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 20 – Subsidiary Guarantors for further details of our guarantors.

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

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will cease to be subject to such covenants. The Indenture also includes customary events of default. As of December 31, 2012, the Partnership is in compliance with all financial and other covenants of the Senior Notes.

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

Bridge Loan Commitment

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

NOTE 11 — COMMITMENTS AND CONTINGENCIES

Services Agreement

We have entered into the Services Agreement with QRM as described in Note 18 – Related Party Transactions. Beginning January 1, 2013, QRM is entitled to a quarterly reimbursement of general and administrative charges based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. Through December 31, 2012, QRM was entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined by the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee.

Property Reclamation Deposit

In connection with the December 2012 Transaction, we acquired a property reclamation deposit for future abandonment and remediation obligations. In connection with a 2006 acquisition between ExxonMobil Corporation and the Fund, $10.7 million was required to be deposited into an escrow account as security for abandonment and remediation obligations. As of December 31, 2013 and 2012, $10.7 million was recorded in other assets 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 the Partnership 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, we were required to provide a $3.0 million letter of credit; the agreement also requires an additional $3.0 million letter of credit to be issued in favor of the seller each year through 2012. Letters of credit totaling $23.5 million are issued as of December 31, 2013.

Environmental Contingencies

As of December 31, 2013 and 2012, we have approximately $2.3 million and $1.9 million in environmental liabilities, respectively, related to the 2013 East Texas Acquisition and the Prize Acquisition. This is management’s best estimate of the costs of remediation and restoration with respect to these environmental matters, although the ultimate cost could differ materially. The environmental liability is recorded in Other liabilities 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.

NPI Obligation

As a part of the December 2012 Acquisition, we assumed a net profit interest obligation. Under the arrangement with the outside interest, 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

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abandonment obligation which is currently reflected in our asset retirement obligations as of December 31, 2013. 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. Beginning in 2013, we were allocated a portion of this obligation as part of the general and administrative expense allocation process.

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 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.

Operating Lease Commitments

QRM is party to an office lease worth approximately $26.8 million that expires in 2022. Beginning in 2013, we were allocated a portion of this expense as part of the general and administrative expense allocation process discussed in Note 19 – Related Party Transactions.

NOTE 12 — PARTNERS’ CAPITAL

Units Outstanding

The table below details the outstanding units as of December 31, 2013, 2012 and 2011. As of December 31, 2013, the Fund owned all preferred units.


	Class C Preferred Units		General Partner		Class B Units		Public Common			Affiliated Common			Subordinated
Balance - December 31, 2010		—		35,729		—		15,000,000			11,297,737			7,145,866
Underwriters’ exercise of over-allotment		—		—		—		2,250,000			—			—
Vested units awarded under our Long Term Incentive Performance Plan		—		—		—		52,798			—			—
Reduction in units to cover individuals’ tax withholdings		—		—		—		(10,519	)		—			—
Preferred Units issued to Predecessor in exchange for Transferred October 2011 Properties		16,666,667		—		—		—			—			—

Balance - December 31, 2011		16,666,667		35,729		—		17,292,279			11,297,737			7,145,866
Vested units awarded under our Long Term Incentive Performance Plan		—		—		—		96,890			—			—
Reduction in units to cover individuals’ tax withholdings		—		—		—		(14,891	)		—			—
Issuance of units to the general partner		—		15,307		—		—			—			—
Affiliated unit sale to the public		—		—		—		11,297,737			(11,297,737	)		—
Conversion of Subordinated Units		—		—		—		—			7,145,866			(7,145,866	)
Unit offerings		—		—		—		22,627,263			—			—

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		—		—		—		218,460			—			—
Reduction in units to cover individuals’ tax withholdings		—		—		—		(34,475	)		—			—
Management incentive fee conversion						6,133,558

Balance - December 31, 2013		16,666,667		51,036		6,133,558		51,483,263			7,145,866			—

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On March 2, 2014 we completed a transaction related to our general partner interest pursuant to a Contribution Agreement. See Note 22 – Subsequent Events for more information.

On January 14, 2014, we filed an automatic registration statement on Form S-3 with the SEC to register our common units, preferred units and our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Note 22 Subsequent Events for details.

On February 22, 2013, our general partner elected to convert the full 80% of the 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.

On December 22, 2012, in connection with the expiration of the subordination period, the subordinated units held by the Fund were converted into affiliated common units and continued to be held by the Fund. The converted units will participate pro rata with the other common units in distributions of available cash.

On December 12, 2012, we issued 12,000,000 common units representing limited partnership interests in us to the public pursuant to a registration statement filed with the SEC (the “December 2012 Equity Offering”). In connection with the December 2012 Equity Offering, the Partnership granted the underwriters an option for 30 days to purchase up to an additional 1,800,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us at a public offering price of $16.24 per unit. Proceeds from the December 2012 Equity Offering, net of transaction costs of $0.2 million and underwriter’s discount of $9.0 million, were approximately $214.9 million.

In connection with the December 2012 Equity Offering, QRE GP purchased 9,289 general partner units in order to maintain its 0.1% ownership percentage in us. The units were purchased at a price of $16.91 per unit for $0.2 million.

On June 1, 2012, we filed a registration statement on Form S-3 with the SEC to register, among other securities, our debt securities, which may be co-issued by QRE FC. The registration statement also registered guarantees of debt securities by OLLC. Refer to Note 21 – Subsidiary Guarantors for details.

On April 17, 2012, we issued 6,202,263 common units representing limited partnership interests in us, and the Fund sold 11,297,737 of its common units it held in us to the public pursuant to a registration statement filed on Form S-1 with the SEC (the “April 2012 Equity Offering”). In connection with the April 2012 Equity Offering, the Partnership granted the underwriters an option for 30 days to purchase up to an additional 2,625,000 common units from the Partnership, which they exercised in full. The common units, including the units issued pursuant to the underwriters’ full exercise of their option, were issued by us or sold by the Fund at $19.18 per unit. Proceeds from the April 2012 Equity Offering, net of transaction costs of $0.5 million and underwriter’s discount of $6.8 million, were approximately $162 million.

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

On October 3, 2011, we issued 16,666,667 of Preferred Units to the Fund in connection with the October 2011 Transaction. See Class C Preferred Units below for further details.

On January 3, 2011, the underwriters exercised their over-allotment option associated with our IPO in December 2010 in full for 2,250,000 common units issued by the Partnership at $20.00 per unit.

Common Units

The common units have limited voting rights as set forth in our partnership agreement.

Pursuant to our partnership agreement, if at any time QRE GP and its affiliates own more than 80% of the outstanding common units, QRE GP has the right, but not the obligation, to purchase all of the remaining common

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units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement. QRE GP may assign this call right to any of its affiliates or to us.

Class B Units

Upon the expiration of the subordinated period on December 22, 2012, and subject to the limitations described below, our general partner has the continuing right, at any time when it has received all or any portion of the management incentive fee for three full consecutive quarters and shall be entitled to receive all or a portion of the management incentive fee for a fourth consecutive quarter, to convert into Class B units up to 80%, such percentage actually converted being referred to as the Applicable Conversion Percentage, of the management incentive fee for the fourth quarter in lieu of receiving a cash payment for such portion of the management incentive fee. Any conversion election made during a quarter must be made before payment of the management incentive fee in respect of the previous quarter and will be effective as of the first day of such quarter, and the Class B units issued upon such conversion will be entitled to distributions as if they were outstanding on the first day of such quarter.

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.

Class C Preferred Units

On October 3, 2011 (the “Issue Date”), we amended our First Amended and Restated Agreement of Limited Partnership to designate and create the Preferred Units and set forth rights, preferences and privileges of such units including distribution rights held by the Preferred Units and us. For the period beginning on the Issue Date and ending on December 31, 2014, we will distribute $0.21 per unit on a quarterly basis. Beginning on January 1, 2015, distributions on Preferred Units will be the greater of $0.475 per unit or the distribution payable on Common Units with respect to such quarter. The Preferred Units are only redeemable for cash in a complete liquidation. The Preferred Units are convertible into common units under specific circumstances at the option of either the holder or the Partnership into common units representing limited partner interests in us on a one-to-one basis, subject to adjustment. The Preferred Units have the same voting rights as common units. As of December 31, 2013 we have accrued a fourth quarter distributions payable of $3.5 million to Preferred Unitholders which were paid in February 2014.

Holders could have converted the Preferred Units to common units on a one-to-one basis prior to October 3, 2013, after 30 consecutive trading days during which the volume-weighted average price for our common units equals or exceeds $27.30 per common unit. In addition, holders may convert the Preferred Units to common units on a one-to-one basis anytime on or after October 3, 2013. As of December 31, 2013 no such conversion had occurred.

If the holders have not converted the Preferred Units to common units by October 3, 2014, we may force conversion on a one-to-one basis, provided that conversion is in the 30 calendar days following 30 consecutive trading days during which the volume-weighted average price for common units equals or exceeds (1) $30.03, provided that (a) an effective shelf registration statement covering resales for the converted units is in place or (2) $27.30, provided that (a) above is satisfied and (b) there exists an arrangement for one or more investment banks to underwrite the converted unit sale following conversion (with proceeds equal to not less than $27.30 less (i) a standard underwriting discount and (ii) a customary discount not to exceed 5% of $27.30).

We may force conversion on a one-to-one basis after October 3, 2016, provided the conversion is in the 30 calendar days following 30 consecutive trading days during which the volume-weighted average price for common units equals or exceeds $27.30 and an effective shelf registration statement covering resales for the converted units is in place.

Registration Rights Agreement

In connection with the acquisition of the October 2011 Transferred Properties, on October 3, 2011, we entered into a Registration Rights Agreement with the Fund (the “Registration Rights Agreement”), which granted certain registration rights to the Fund, including rights to (a) cause the Partnership to file with the SEC up to five shelf registration statements under the Securities Act for the resales of the common units to be issued upon conversion of

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the Preferred Units, and in certain circumstances, the resales of the Preferred Units, and (b) participate in future underwritten public offerings of the our common units.

The Fund may exercise its right to request that a shelf registration statement be filed any time after June 1, 2012. In addition, we agreed to use commercially reasonable efforts (a) to prepare and file a shelf registration statement within 60 days of receiving a request from the Fund and (b) to cause the shelf registration statement to be declared effective by the SEC no later than 180 days after its filing. The Registration Rights Agreement contains customary representations, warranties and covenants, and customary provisions regarding rights of indemnification between the parties with respect to certain applicable securities law liabilities.

These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective. As of March 2, 2014, the Fund has not requested a shelf registration be filed for the Preferred Units.

Subordinated Units

The principal difference between our common and subordinated units was that, in any quarter during the subordination period, the subordinated units were entitled to receive the minimum quarterly distribution of $0.4125 per unit ($1.65 per unit on an annualized basis) only after the common units have received their minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Accordingly, holders of subordinated units may receive a smaller distribution than holders of common units or no distribution at all. Subordinated units will not accrue arrearages.

During Subordination Period. Our partnership agreement, as amended, requires that we make distributions of available cash from operating surplus for any quarter in the following manner during the subordination period:

•

first, to QRE GP and common unitholders in accordance with their percentage interest until there has been distributed in respect of each common unit then outstanding an amount equal to the minimum quarterly distribution of $0.4125 per unit per whole quarter (or $1.65 per year);

•

second, to QRE GP and common unitholders in accordance with their percentage interest until there has been distributed in respect of each common unit then outstanding an amount equal to the cumulative common unit arrearage existing with respect to such quarter;

•

third, to QRE GP in accordance with its percentage interest and to the unitholders holding subordinated units, pro rata, a percentage equal to 100% less QRE GP’s percentage interest, until there has been distributed in respect of each subordinated unit then outstanding an amount equal to the minimum quarterly distribution for such quarter; and

•

thereafter, to QRE GP and all unitholders (other than preferred unitholders), pro rata.

After Subordination Period. Effective December 22, 2012 the subordinated period ended. As a result, each outstanding subordinated unit converted into one common unit and will participate pro rata with the other common units in distributions of available cash.

QRE GP Interest

QRE GP owns a 0.1% interest in us. This interest entitles QRE GP to receive distributions of available cash from operating surplus as discussed further below under Cash Distributions. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and QRE GP will receive.

QRE GP has sole responsibility for conducting our business and managing our operations. QRE GP’s board of directors and executive officers will make decisions on our behalf.

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Allocations of Net Income

Net income (loss) is reduced by noncontrolling interest and is then allocated to the preferred and Class B unitholders to the extent distributions are made or accrued to them during the period and 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, or at our general partner’s sole discretion, or in three equal installments within 15, 45, and 75 days following the end of each quarter, we distribute all of our available cash to preferred unitholders, in arrears, and common unitholders of record on the applicable record date, as determined by QRE GP.

Available cash, for any quarter prior to liquidation, consists of all cash on hand at the end of the quarter:

•

less the amount of cash reserves established by QRE GP to:

(i.)

provide for the proper conduct of our business;

(ii.)

comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation; and

(iii.)

provide funds for distribution to our unitholders and to QRE GP for any one or more of the next four quarters.

•

less, the aggregate Preferred Unit distribution accrued and payable for the quarter;

•

plus, if QRE GP so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter.

Commencing with the fourth quarter of 2013, we will distribute to common unitholders on a monthly basis. We intend to continue to make regular cash distributions to unitholders on a monthly or quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit facility prohibits us from making cash distributions if any potential default or event of default, as defined in our credit facility, occurs or would result from the cash distribution.

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

As of December 31, 2013, QRE GP owns a 0.1% general partner interest in us, represented by 51,036 general partner units. QRE GP has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. QRE GP’s initial 0.1% interest in distributions will be reduced if we issue additional units in the future and QRE GP does not contribute a proportionate share of capital to us to maintain its 0.1% general partnership interest.

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The following table shows the cash distributions declared or paid to date:


									Limited Partners
											Affiliated
For the period ended	Distributions to Preferred Unitholders		Distributions per Preferred Unit(1)		General Partner		Class B		Public Common		Common		Subordinated		Total Distributions to Other Unitholders		Distributions per other units

December 31, 2011 (2)	$	3,424	$	0.21	$	16	$		$	8,344	$	5,368	$	3,393	$	17,121	$	0.4750
March 31, 2012 (2)		3,500		0.21		20				17,892		—		3,394		21,306		0.4750
June 30, 2012 (2)		3,500		0.21		20				18,584		—		3,484		22,088		0.4875
September 30, 2012 (2)		3,500		0.21		20				18,529		—		3,484		22,033		0.4875
December 31, 2012 (2)		3,500		0.21		25				25,275		3,484		—		28,784		0.4875
December 31, 2012 (3)		—		—		—		2,990		—		—		—		2,990		0.4875
March 31, 2013 (2)		3,500		0.21		25		2,990		25,480		3,484		—		31,979		0.4875
June 30, 2013 (2)		3,500		0.21		25		2,990		25,475		3,484		—		31,974		0.4875
September 30, 2013 (2)		3,500		0.21		25		2,881		25,465		3,484		—		31,855		0.4875
December 31, 2013 (2)		3,500		0.21		—		—		—		—		—		—		—
December 31, 2013 (4)		—		—		8		987		8,489		1,161		—		10,645		0.1625
December 31, 2013 (5)		—		—		8		997		8,489		1,161		—		10,655		0.1625
December 31, 2013 (6)						8		997		8,489		1,161		—		10,655		0.1625

⁽¹⁾	Preferred Units were prorated a quarterly distribution for the portion of the fourth quarter beginning on October 3, 2011 through December 31, 2011 in accordance with the Partnership Agreement.

⁽²⁾	Distributions were made within 45 days after the end of each quarter.

⁽³⁾	The December 31, 2012 and March 31, 2013 distributions to the Class B units were paid 45 days after the end of the first quarter 2013.

⁽⁴⁾	In December 2013, the Board of Directors approved the first monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in January 2014 to the unitholders of record as of January 13, 2014. This distribution was recorded in the fourth quarter 2013.

⁽⁵⁾

In January 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in February 2014 to the unitholders of record as of February 10, 2014. For more information see Note 22 – Subsequent Events for further details.

⁽⁶⁾

In February 2014, the Board of Directors approved the third monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which will be paid in March 2014 to the unitholders of record as of March 10, 2014. For more information see Note 22 – Subsequent Events for further details.

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NOTE 13 — NET INCOME (LOSS) PER LIMITED PARTNER UNIT

The following sets forth the calculation of net income (loss) per limited partner unit for the years ended December 31, 2013, 2012 and 2011:


	Year Ended
	December 31, 2013			December 31, 2012			December 31, 2011
Net income	$	61,628		$	79,751		$	88,295
Net income (loss) attributable to noncontrolling interest		(663	)		—			—

Net income (loss) attributable to QR Energy, LP		60,965			79,751			88,295

Net (income) loss attributable to predecessor operations		—			(37,350	)		(76,249	)
Distribution on Class C convertible preferred units		(14,000	)		(14,000	)		(3,424	)
Amortization of preferred unit discount		(15,553	)		(14,930	)		(3,638	)
Distribution on Class B units		(12,838	)		—			—

Net income (loss) available to other unitholders		18,574			13,471			4,984
Less: general partner’s interest in net income (loss)		3,391			6,149			1,575

Limited partner’s interest in net income (loss)	$	15,183		$	7,322		$	3,409

Common unitholders’ interest in net income (loss)	$	15,183		$	6,570		$	2,730
Subordinated unitholders’ interest in net income (loss)	$	—		$	752		$	679
Net income (loss) attributable to QR Energy, LP per limited partner unit:
Common unitholders’ (basic)	$	0.26		$	0.19		$	0.10
Common unitholders’ (diluted)	$	0.26		$	0.19		$	0.10
Subordinated unitholders’ (basic and diluted)	$	—		$	0.11		$	0.10
Weighted average number of limited partner units outstanding (in thousands):
Common units (basic)		58,524			35,132			28,728
Common units (diluted) (1) (2)		58,524			35,282			28,728
Subordinated units (basic and diluted)		—			6,970			7,146

⁽¹⁾

For the years ended December 31, 2013, 2012 and 2011, we had weighted average preferred units outstanding of 16,666,667, 16,666,667, and 4,109,589, respectively. For the years ended December 31, 2013, 2012 and 2011, we had 5,088,831, zero, and zero, respectively, of weighted average Class B units outstanding. 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 excluded in the diluted earnings per unit calculation for the years ended December 31, 2013, 2012 and 2011 as they were antidilutive for the period.

⁽²⁾

In connection with the expiration of the subordination period on December 22, 2012, the general partner had the right to convert all or a portion of the fourth quarter management incentive fee into Class B common units. In 2012, we had weighted average Class B units of 150,896 which were contingently convertible. The Class B units were included in the 2012 diluted earnings per unit calculation as they were dilutive to the period.

Net income (loss) per limited partner unit is determined by dividing the limited partners’ interest in net income, and net income available to the common unitholders, by the weighted average number of limited partner units outstanding during the period.

F-38

NOTE 14 — ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

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


	Gains/(loss) on
	Available-For- Sale			Postretirement
	Securities			Benefits		Total
Accumulated comprehensive income as of December 31, 2012	$	—		$	—	$	—
Other comprehensive income before reclassifications		631			4,061		4,692
Amounts reclassified from accumulated other comprehensive income (1)		(18	)		—		(18	)

Net current period other comprehensive income		613			4,061		4,674

Accumulated comprehensive income as of December 31, 2013	$	613		$	4,061	$	4,674


Accumulated comprehensive income attributable to non-controlling interest		273			1,657		1,930

Accumulated comprehensive income attributable to QR Energy, LP	$	340		$	2,404	$	2,744

⁽¹⁾	Amounts were reclassified from accumulated other comprehensive income / (loss) into “Other income (expense), net” in the Consolidated Statement of Operations.

NOTE 15 — EQUITY-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.

On February 3, 2014 we filed a definitive proxy statement on Form 14/A, which provides information regarding a special meeting of limited partners to be held on March 10, 2014 to hold a unitholder vote on an amendment to our Long-Term Incentive Plan to increase the number of units under the plan by 3,000,000. See Note 22 – Subsequent Events.

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 years ended December 31, 2013, 2012 and 2011, we recognized compensation expense related to the outstanding awards of $6.1 million, $3.1 million, and $1.4 million, respectively. As of December 31, 2013, we had 754,822 of Restricted Units outstanding with unrecognized grant date fair value compensation expense of $10.2 million, which we expect to be recognized over a weighted-average period of approximately 1.8 years. The amount of unrecognized compensation expense does not necessarily represent the amount that will ultimately be recognized by us in our statements of operations.

Performance Restricted Units.

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The performance awards 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 shares to be issued will range from 0 – 225% of the initial shares granted. For Performance Units, we recognize compensation expense using a straight-line amortization of the grant date fair value over the performance period. For the years ended December 31, 2013 and 2012, we recognized compensation expense related to the outstanding awards of $0.8 million and $0.2 million. As of December 31, 2013, we had 267,489 of Performance Units outstanding with unrecognized grant date fair value compensation expense of $1.7 million, which we expect to be recognized over a weighted-average period of approximately 1.8 years. The amount of unrecognized compensation expense does not necessarily represent the amount that will ultimately be recognized by us in our statements of operations.

The following assumptions were used for the Performance Units based on market conditions using a Monte Carlo model to estimate the grant date fair value of the awards. The four primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns, correlation in movement of total unitholder return relative to a relevant peer group and the expected distribution rate. Risk-free rate was based on the Federal Reserve for treasuries equal to the remaining duration of the performance period, which was 0.4% for the 2013 and 2012 grants. Volatility was determined based on the annualized daily historical volatility, which was approximately 29% for the 2013 grants and ranged from 31% to 32% for the 2012 grants. Correlation in movement of total unitholder return was determined based on a correlation matrix that was created which identifies total shareholder return correlations for each pair of companies in the peer group, including the Partnership. The paired returns in the correlation matrix ranged from 33.7% to 56.6% for the Partnership and its peer group. The expected distribution rate is calculated using a trailing six month average for the Partnership and its peer group as of the date of grant, which was 11% and 10% for the 2013 and 2012 grants. Based on these inputs discussed above, a ranking was projected identifying the Partnership’s rank relative to the peer group for each award period which determines the anticipated payout. The weighted average grant date fair value per unit, using the method described above, was $10.03 and $10.35 for the years ended December 31, 2013 and 2012, respectively, and is being recognized ratably in expense over the service period.

Unit-Based Awards Activity

The following table summarizes the Partnership’s unit-based awards for the years ended December 31, 2013, 2012 and 2011, (in thousands, except per unit amounts):


	Number of Unvested Service Restricted Units			Weighted Average Grant-Date Fair Value		Number of Unvested Performance Restricted Units			Weighted Average Grant-Date Fair Value
Unvested units, December 31, 2010		148,160		$	20.03		—		$	—
Granted		214,588			20.51		—			—
Forfeited		(38,586	)		20.75		—			—
Vested		(52,798	)		20.31		—			—

Unvested units, December 31, 2011		271,364		$	20.26		—		$	—
Granted		437,211			18.22		121,137			10.35
Forfeited		(61,444	)		19.47		(3,055	)		10.45
Vested		(96,890	)		20.05		—			—

Unvested units, December 31, 2012		550,241		$	18.80		118,082		$	10.34
Granted		491,847			17.97		149,407			10.03
Forfeited		(68,806	)		18.41		—			—
Vested		(218,460	)		19.01		—			—

Unvested units, December 31, 2013		754,822		$	18.22		267,489		$	10.17

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NOTE 16 — ACCRUED AND OTHER LIABILITIES

As of December 31, 2013 and December 31, 2012 we had the following accrued and other liabilities:


	December 31, 2013		December 31, 2012
Accrued lease operating expenses	$	20,297	$	11,173
Accrued capital spending		16,316		6,109
Distributions payable (1)		14,155		3,500
Senior notes accrued interest		11,563		11,563
Accrued production and other taxes		6,270		7,401
Gas imbalance liability (2)		6,214		5,351
Other		4,230		1,187

	$	79,045	$	46,284

⁽¹⁾	For the year ended December 31, 2013 and 2012, balance includes preferred distributions payable to affiliates of $3.5 million.

⁽²⁾

We account for our natural gas imbalances under the sales method. We had overproduced liabilities of $6.2 million and $5.4 million included in accrued liabilities on our consolidated balance sheets as of December 31, 2013 and December 31, 2012, respectively, for overproduced positions which were beyond ultimate recoverability of remaining natural gas reserves. As of December 31, 2013, our gross underproduced natural gas position was approximately $4.1 million (1.5 MMcf) and our gross overproduced natural gas position was approximately $6.2 million (2.1 MMcf). These gross positions were valued at $4.62 per Mcf for underproduced natural gas positions and $4.31 per Mcf for overproduced natural gas positions without regard to remaining natural gas reserves. As of December 31, 2012, our gross underproduced natural gas position was approximately $1.2 million (1.5 MMcf) and our gross overproduced natural gas position was approximately $5.4 million (2.1 MMcf). These gross positions were valued at $3.46 per Mcf for underproduced natural gas positions and $3.41 per Mcf for overproduced natural gas positions without regard to remaining natural gas reserves.

NOTE 17 — SIGNIFICANT CUSTOMERS

The following table indicates our significant customers which accounted for more than 10% of our total revenues for the periods indicated:


	December 31, 2013			December 31, 2012			December 31, 2011
Customer A		27	%		33	%		29	%

Customer B		21	%		13	%			(1)

Customer C		17	%			(1)			(1)

Customer D			(1)		12	%		11	%

Customer E			(1)			(1)		12	%

⁽¹⁾	These customers accounted for less than 10% of total revenues for the periods indicated.

Because there are numerous other parties available to purchase our oil and gas production, we believe that the loss of any individual purchaser would not materially affect our ability to sell our natural gas or crude oil production.

NOTE 18 — INCOME TAXES

Our wholly owned subsidiaries are treated as partnerships for federal income tax purposes but are subject to Texas margin taxes. Our controlling interest in a privately held C-Corp is subject to federal income tax. We recorded a deferred tax asset of $1.1 million and $0.3 million related to our operations located in Texas as of December 31, 2013 and 2012 and a deferred tax liability of $3.2 million and $0.4 million as of December 31, 2013 and 2012. The deferred tax asset and deferred tax liability are presented net as a deferred tax liability of $2.1 million on the consolidated balance sheet as of December 31, 2013 and as a deferred tax liability of $0.1 million on the consolidated balance sheet as of December 31, 2012. Our provision for income taxes was a net benefit of $0.4 million and a net expense of $0.5 million and $0.9 million for years ended December 31, 2013, 2012 and 2011.

F-41

Income tax expense (benefit) is summarized as follows:


	December 31, 2013			December 31, 2012		December 31, 2011
Current	$			$		$
Federal		17			—		—
State		(66	)		156		1

Total		(49	)		156		1


Deferred
Federal		(202	)		—		—
State		(102	)		372		849

Total		(304	)		372		849


Total expense income tax (benefit)		(353	)		528		850

Federal income tax expense (benefit) differs from expected tax expense (computed by applying the statutory federal income tax rate of 34% to income (loss) before income taxes) as follows:


	December 31, 2013			December 31, 2012			December 31, 2011
Computed expected tax rate		34.00	%		34.00	%		34.00	%
Tax adjustment for partnership income		(33.55	)%		(34.00	)%		(34.00	)%
Change in valuation allowance		(0.32	)%		—	%		—	%
Other		(0.69	)%		0.66	%		0.95	%

		(0.56	)%		0.66	%		0.95	%

The tax effects of temporary differences and net operating losses that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2013 and 2012 are as follows:


	December 31, 2013			December 31, 2012
Deferred Tax Assets	$			$
Asset retirement obligation		1,740			—
Post-retirement benefit costs		845			—
Net operating losses		2,043			—
Other		—			300

Total deferred tax assets		4,628			300

Valuation allowance		(3,582	)		—

Net deferred tax assets		1,046			300


Deferred Tax Liabilities
Unrealized gain on investments		223			—
Depreciation		1,847			—
Pension costs		1,031			—
Other		59			402

Total deferred tax liabilities		3,160			402


Net Deferred Tax Asset (Liability)		(2,114	)		(102	)

As of December 31, 2013, the total NOL carryforward consists of $6 million of federal NOL carryforwards, which expire between 2026 and 2030. The Partnership has not fully recognized the deferred tax assets for certain items in advance of their deductibility for income tax purposes due to the uncertainty of realization. The benefit of these items will be recognized in future years to the extent that such deductions are used to reduce taxable income.

As of December 31, 2013, we have not identified any uncertain tax provisions.

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NOTE 19 — RELATED PARTY TRANSACTIONS

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

As of December 31, 2013, affiliates of the Fund owned 100% of QRE GP, and an aggregate 29.2% limited partner interest in us represented by all of our 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 represented by 6,133,558 Class B units. Our Chief Executive Officer and Chief Operating Officer have a beneficial ownership in QRE GP and the Fund.

As of December 31, 2012, affiliates of the Fund owned 100% of QRE GP, and an aggregate 31.7% limited partner interest in us represented by all of our 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. Our Chief Executive Officer and Chief Operating Officer have a beneficial ownership in QRE GP and the Fund.

Contracts with QRE GP and Its Affiliates

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

Services Agreement

On December 22, 2010, in connection with the closing of the IPO, we entered into the Services Agreement with QRM, QRE GP and OLLC, pursuant to which QRM will provide the administrative and acquisition advisory services necessary to allow QRE GP to manage, operate and grow our business. We do not have any employees. The Services Agreement requires that employees of QRM (including the persons who are executive officers of QRE GP) devote such portion of their time as may be reasonable and necessary for the operation of our business. The executive officers of QRE GP currently devote a majority of their time to our business, and we expect them to continue to do so for the foreseeable future.

Under the Services Agreement, from the closing of the IPO through December 31, 2012, QRM was entitled to a quarterly administrative services fee equal to 3.5% of the Adjusted EBITDA, as defined by the Services Agreement, generated by us during the preceding quarter, calculated prior to the payment of the fee.

Beginning on January 1, 2013, QRM became entitled to a quarterly reimbursement of general and administrative charges based on the allocation of charges between the Fund and us based on the estimated use of such services by each party. The fee included direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If the Fund raises a second fund, the quarterly administrative services costs will be further divided to include the second fund as well. QRM will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement.

For the years ended December 31, 2013, 2012 and 2011, the Fund charged us $33 million, $7.3 million, and $2.5 million, respectively, in administrative services fee in accordance with the Services Agreement, and we will reimburse QRE GP for such payments it makes to QRM.

F-43

In connection with the management of our business, QRM provides services for invoicing and collecting of our revenues as well as processing of payments to our vendors. Periodically QRM remits cash to us for the net working capital received on our behalf. Changes in the affiliate (payable)/receivable balances during the years ended December 31, 2013 and 2012 are included below:


Net affiliate payable as of December 31, 2011	$	3,734
Revenues and other increases		256,496
Expenditures		(208,780	)
Settlements from the Fund		(51,450	)

Net affiliate receivable as of December 31, 2012		—
Revenues and other increases		403,867
Expenditures		(264,092	)
Settlements from the Fund		(135,860	)

Net affiliate receivable as of December 31, 2013	$	3,915

Other Contributions to Partners’ Capital

Other contributions to partners’ capital include the following items for the period indicated:


	Year Ended December 31, 2013		Year Ended December 31, 2012		Year Ended December 31, 2011
Noncash general and administrative expense contributed by the Fund(1)	$	—	$	31,591	$	17,364
Noncash general and administrative expense contributed by the Predecessor(2)		—		6,485		17,357
Fair value of interest rate derivatives novated to us from the Fund(3)		—		—		2,600
Prepaid insurance incurred by the Fund on our behalf(4)		—		—		224

Total other contributions from affiliates	$	—	$	38,076	$	37,545

⁽¹⁾	Represents our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us.

⁽²⁾

Represents our share of allocable general and administrative expenses incurred by QRM on our behalf, but not reimbursable by us for the December 2012 Transferred Properties for the years ended December 31, 2012 and 2011 and for the October 2011 Transferred Properties for the period from January 1 to September 30, 2011.

⁽³⁾

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

⁽⁴⁾	QRM also incurred prepaid insurance on our behalf, but not reimbursable by us.

Cash Contributions from the Predecessor

The following table presents cash received by the Predecessor on our behalf related to the December 2012 Transferred Properties and October 2011 Transferred Properties for the following periods prior to our acquisition of the net assets on December 28, 2012 and October 3, 2011, respectively:


	Year ended December 31, 2012			Year ended December 31, 2011
Cash receipts	$	(109,274	)	$	(204,898	)
Production expenditures paid		41,528			80,889
Derivative buyup payment		—			42,653
Interest paid		4,050			9,981
Capital expenditures paid		28,723			45,868

Cash distributions to the Predecessor	$	(34,973	)	$	(25,507	)

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Omnibus Agreement

On December 22, 2010, in connection with the closing of our IPO, we entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among us, QRE GP, OLLC, the Fund, the Predecessor and QA Global.

Under the terms of the Omnibus Agreement, the Fund will offer us the first option to purchase properties that it may offer for sale, so long as the properties consist of at least 70% proved developed producing reserves. The 70% threshold is a value-weighted determination made by the Fund. Additionally, the Fund will allow us to participate in acquisition opportunities to the extent that it invests any of the remaining approximately $113.2 million of its equity capital or acquires reserves as follow-on investments that are associated with its existing reserves. Specifically, the Fund will offer us the first opportunity to participate in at least 25% of each acquisition opportunity available to it, so long as at least 70% of the allocated value is attributable to proved developed producing reserves. These contractual obligations will remain in effect until December 21, 2015.

The Omnibus Agreement provides that the Fund will indemnify us against: (i) title defects, subject to a $75,000 per claim de minimus exception, for amounts in excess of a $4.0 million threshold, and (ii) income taxes attributable to pre-closing operations as of the IPO Closing Date. The Fund indemnification obligation will (i) survive for one year after the closing of our IPO with respect to title, and (ii) terminate upon the expiration of the applicable statute of limitations with respect to income taxes. We will indemnify the Fund against certain potential environmental claims, losses and expenses associated with the operation of our business that arise after the consummation of our IPO.

Management Incentive Fee

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

•

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

•

adjusted for our commodity derivative contracts; and

•

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

For the years ended December 31, 2013, 2012 and 2011, the management incentive fee earned by QRE GP was $3.4 million, $6.1 million and $1.6 million, respectively. The fourth quarter 2012 management incentive fee was reduced by the portion of the management incentive fee converted as discussed below under General Partner’s Right to Convert Management Incentive Fee into Class B Units.

General Partner’s Right to Convert Management Incentive Fee into Class B Units

From and after the end of the subordination period and subject to the limitations described below, our general partner has the continuing right, at any time when it has received all or any portion of the management incentive fee for three full consecutive quarters and shall be entitled to receive all or a portion of the management incentive fee for a fourth consecutive quarter, to convert into Class B units up to 80%, such percentage actually converted being referred to as the Applicable Conversion Percentage, of the management incentive fee for the fourth quarter in lieu of receiving a cash payment for such portion of the management incentive fee. Any Conversion Election made during a quarter must be made before payment of the management incentive fee in respect of the previous quarter and will be effective as of the first day of such quarter, and the Class B units issued upon such conversion will be entitled to distributions as if they were outstanding on the first day of such quarter.

The number of Class B units (rounded to the nearest whole number) to be issued in connection with such a conversion will be equal to (a) the product of: (i) the Applicable Conversion Percentage; and (ii) the average of the

F-45

management incentive fee paid to our general partner for the quarter immediately preceding the quarter for which such fee is to be converted and the management incentive fee payable to our general partner for the quarter for which such fee is to be converted, divided by (b) the cash distribution per unit for the most recently completed quarter.

We refer to such conversion as a “Conversion Election.” The reduction in the management incentive fee as a result of any conversion will directly offset the increase in distributions required by the newly issued Class B units.

In the event of such Conversion Election, unless we experience a change of control, our general partner will not be permitted to exercise the Conversion Election again until (i) the completion of the fourth full calendar quarter following the previous Conversion Election and (ii) the Gross Management Incentive Fee Base has increased to 115% of the Gross Management Incentive Fee Base as of the immediately preceding conversion date.

The subordination period on our subordinated units ended on December 31, 2012 and our general partner had received a management incentive fee for three full consecutive quarters. On February 22, 2013, our general partner elected to convert 80% of the 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. The general partner received a reduced fourth quarter management incentive fee of $0.7 million and received a distribution on the Class B units related to the fourth quarter 2012.

On March 2, 2014 we completed a transaction related to our general partner interest pursuant to a Contribution Agreement. See Note 22 – Subsequent Events for more information.

Purchase and Sale Agreements

On December 28, 2012, we completed an acquisition of certain oil and gas properties in Florida from the Fund for an aggregate price of $143.6 million, pursuant to the December 2012 Purchase Agreement. In exchange for the assets, we assumed $115.0 million in debt from the Fund and paid the remaining $28.6 million in cash.

On October 3, 2011, we completed an acquisition of certain oil and gas properties located in the Permian Basin, Ark-La-Tex and Mid-Continent areas from the Fund for an aggregate purchase price of $578.8 million, pursuant to a Purchase and Sale Agreement (the “October 2011 Purchase Agreement”) dated September 12, 2011. In exchange for the assets, we assumed $227.0 million in debt from the Fund which was repaid at closing and issued to the Fund 16,666,667 unregistered Preferred Units.

See Note 1 – Organization and Operations and Note 4 – Acquisitions for further discussion of the acquisitions and Note 2 – Summary of Significant Accounting Policies for discussion of the basis of presentation in the financial statements.

Lease Guarantees

The Fund has entered into various lease contracts that can routinely extend beyond five years which list the Partnership as a guarantor. See Note 11 – Commitments and Contingencies.

Long–Term Incentive Plan

On December 22, 2010, in connection with the closing of the IPO, the Board of Directors of QRE GP adopted the Plan to compensate employees, officers, consultants and directors of QRE GP and those of its affiliates, including QRM, who perform services for us. As of December 31, 2013, 2012 and 2011, we had 1,022,311, 668,323, and 271,364 unvested restricted and performance unit awards outstanding with remaining unamortized costs of $11.9 million, $9.0 million, and $4.8 million, respectively. For additional discussion regarding the Plan see Note 15 – Equity-Based Compensation.

Distributions of Available Cash to QRE GP and Affiliates

We will generally make cash distributions to our unitholders and QRE GP pro rata, including QRE GP and our affiliates. The Partnership made cash distributions to QRE GP and our affiliates during 2012 and 2013 as discussed in Note 12 – Partners’ Capital.

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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.

Farmout Agreement with Related Party

In January 2014, we entered into a Farmout Agreement with Tanos Exploration II, LLC (“Tanos”), a Quantum Energy Partners affiliate, whereas Tanos is to be the operator of certain wells until completion or other termination criteria are met.

NOTE 20 – SUPPLEMENTAL CASH FLOW INFORMATION

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


	Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011
Supplemental Cash Flow Information
Cash paid during the period for interest	$	46,504		$	41,040		$	22,465
Cash paid for income tax		—			18			—
Non-cash Investing and Financing Activities
Non-cash consideration paid for transferred properties from the Fund	$	—		$	—		$	(354,500	)
Excess consideration of fair value of transferred properties from the Fund		—			68,861			102,454
Change in accrued capital expenditures		(10,207	)		(3,481	)		9,551
Insurance premium financed		—			—			224
Receivable from QRE GP in connection with equity issuance		(165	)		157			—
Interest rate swaps novated from the Fund		—			—			2,600
Accrued distributions		(14,155	)		(3,500	)		(20,545	)
General and administrative expense allocated from the Fund		—			38,076			34,721
Management incentive fee accrued		—			—			(1,572	)
Amortization of increasing rate distributions(1)		15,553			14,930			3,638

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

NOTE 21 – SUBSIDIARY GUARANTORS

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

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

F-47

Condensed Consolidating Balance Sheets


	December 31, 2013
	Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non- Guarantor		Eliminations			Consolidated
Assets
Current assets
Cash	$	78	$	—	$	10,575	$	2,707	$	—		$	13,360
Accounts receivable		—		—		55,073		2,939		(570	)		57,442
Due from affiliates		234,746		—		—		—		(230,831	)		3,915
Derivative instruments		—		—		27,485		—		—			27,485
Prepaid and other current assets		—		—		1,718		141		—			1,859

Total current assets		234,824		—		94,851		5,787		(231,401	)		104,061

Noncurrent assets
Oil and natural gas properties and other property and equipment, net		—		—		1,591,015		13,968		—			1,604,983
Derivative instruments		—		—		62,131		—		—			62,131
Investment in subsidiaries		711,734		—		16,478		—		(728,212	)		—
Other assets		4,663		—		20,176		19,913		—			44,752

Total noncurrent assets		716,397		—		1,689,800		33,881		(728,212	)		1,711,866

Total assets	$	951,221	$	—	$	1,784,651	$	39,668	$	(959,613	)	$	1,815,927


Liabilities and Partners’ Capital
Current liabilities
Current portions of asset retirement obligations	$	—	$	—	$	4,310	$	—	$	—		$	4,310
Due to affiliates		—		—		230,831		—		(230,831	)		—
Derivative instruments		—		—		11,233		—		—			11,233
Accrued and other liabilities		25,718		—		52,100		1,797		(570	)		79,045

Total current liabilities		25,718		—		298,474		1,797		(231,401	)		94,588

Noncurrent liabilities
Long-term debt		296,593		—		615,000		—		—			911,593
Derivative instruments		—		—		6,251		—		—			6,251
Asset retirement obligations		—		—		145,893		5,118		—			151,011
Other liabilities		—		—		7,299		7,726		—			15,025

Total noncurrent liabilities		296,593		—		774,443		12,844		—			1,083,880

Partners’ capital
QR Energy, LP partners’ capital		628,910		—		711,734		25,027		(736,761	)		628,910
Noncontrolling interest		—		—		—		—		8,549			8,549

Total partners’ capital		628,910		—		711,734		25,027		(728,212	)		637,459

Total liabilities and partners’ capital	$	951,221	$	—	$	1,784,651	$	39,668	$	(959,613	)	$	1,815,927

F-48

Condensed Consolidating Statements of Operations


	Parent Co-Issuer			Subsidiary Co-Issuer		Guarantor			Non- Guarantor		Eliminations			Consolidated
Year Ended December 31, 2013
Total revenues	$	—		$	—	$	447,077		$	10,262	$	(1,710	)	$	455,629
Expenses
Production and disposal and related expenses		—			—		172,998			9,410		(1,710	)		180,698
Depreciation, depletion and amortization		—			—		115,039			145		—			115,184
General and administrative		7,101			—		34,800			—		—			41,901

Accretion of asset retirement obligations and acquisition and transaction costs		—			—		8,831			112		—			8,943

Total expenses		7,101			—		331,668			9,667		(1,710	)		346,726

Operating income		(7,101	)		—		115,409			595		—			108,903
Gain (loss) on commodity derivative contracts, net		—			—		(1,217	)		—		—			(1,217	)
Interest expense, net, income tax expense and other income, net		(29,468	)		—		(17,574	)		984		—			(46,058	)
Equity in earnings		97,534			—		916			—		(98,450	)		—

Net (loss) income		60,965			—		97,534			1,579		(98,450	)		61,628
Less: Net income attributable to noncontrolling interest		—			—		—			—		663			663

Net income (loss) attributable to QR Energy, LP	$	60,965		$	—	$	97,534		$	1,579	$	(99,113	)	$	60,965

Condensed Consolidating Statements of Comprehensive Income


	Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non- Guarantor			Eliminations			Consolidated
Year Ended December 31, 2013
Net income (loss)	$	60,965	$	—	$	97,534	$	1,579		$	(98,450	)	$	61,628
Other comprehensive income, net of tax:
Reclassification adjustment for available-for-sale securities		—		—		—		(18	)		—			(18	)
Change in fair value of available-for-sale securities		340		—		340		631			(680	)		631
Pension and postretirement benefit:
Actuarial gain		2,404		—		2,404		4,061			(4,808	)		4,061

Total other comprehensive income		2,744		—		2,744		4,674			(5,488	)		4,674

Total comprehensive income (loss)		63,709		—		100,278		6,253			(103,938	)		66,302
Less: Comprehensive income attributable to noncontrolling interest		—		—		—		—			2,593			2,593

Comprehensive income (loss) attributable to QR Energy, LP	$	63,709	$	—	$	100,278	$	6,253		$	(106,531	)	$	63,709

F-49

Condensed Consolidating Statements of Cash Flows


	Parent Co-Issuer			Subsidiary Co-Issuer		Guarantor			Non- Guarantor			Eliminations			Consolidated
Year Ended December 31, 2013
Net cash (used in) provided by operating activities	$	(22,103	)	$	—	$	222,997		$	1,251		$	—		$	202,145
Cash flows from investing activities
Additions to oil and natural gas properties		—			—		(87,936	)		(311	)		—			(88,247	)
Acquisitions		—			—		(131,715	)		3,481			—			(128,234	)
Distributions from subsidiaries		167,470			—		—			—			(167,470	)		—
Proceeds from sale of available-for-sale securities		—			—		—			8,535			—			8,535
Purchases of available-for-sale securities		—			—		—			(10,249	)		—			(10,249	)

Net cash (used in) provided by investing activities		167,470			—		(219,651	)		1,456			(167,470	)		(218,195	)

Cash flows from financing activities
Distributions to unitholders		(141,582	)		—		—			—			—			(141,582	)
Proceeds from bank borrowings		—			—		180,000			—			—			180,000
Repayments on bank/intercompany borrowings		—			—		(35,000	)		—			—			(35,000	)
Distributions to Parent		—			—		(167,470	)		—			167,470			—
Other		(3,775	)		—		(2,069	)		—			—			(5,844	)

Net cash (used in) provided by financing activities		(145,357	)		—		(24,539	)		—			167,470			(2,426	)

Net increase (decrease) in cash		10			—		(21,193	)		2,707			—			(18,476	)
Cash at beginning of period		68			—		31,768			—			—			31,836

Cash at end of period	$	78		$	—	$	10,575		$	2,707		$	—		$	13,360

NOTE 22 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after December 31, 2013, up until the issuance of the financial statements.

On January 31, 2014, we closed the acquisition of primarily natural gas properties located in East Texas from a private seller for $36.0 million in cash, subject to customary purchase price adjustments, using funds drawn on our revolving credit facility.

On February 3, 2014, we filed a definitive proxy statement on Form 14/A, which provides information regarding a special meeting of limited partners to be held on March 10, 2014 to hold a unitholder vote on an amendment to our Long-Term Incentive Plan to increase the number of units under the plan by 3,000,000.

On February 20, 2014, we entered into a purchase and sale agreement of primarily oil properties located in East Texas from a private seller for $11.1 million, subject to customary purchase price adjustments.

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

Effective March 2, 2014, we entered into the sixth amendment to the Credit Agreement, which permits the GP Buyout Transaction.

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

On January 24, 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in February 2014 to the unitholders of record as of February 10, 2014.

On February 28, 2014, the Board of Directors approved the third monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 and will be paid in March 2014 to the unitholders of record as of March 10, 2014. As a result of this declaration, a management incentive fee related to the fourth quarter 2013 in the amount of $1.3 million will be recognized during the three months ended March 31, 2014.

F-50

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Capitalized Costs

The following table sets forth the capitalized costs related to our oil and natural gas producing activities as of the dates indicated:


	December 31,
	2013			2012
Evaluated oil and natural gas properties	$	1,905,110		$	1,656,146
Unevaluated oil and natural gas properties		4,320			11,500

Gross oil and natural gas properties		1,909,430			1,667,646
Accumulated depreciation, depletion and amortization		(318,415	)		(203,377	)

Net capitalized costs	$	1,591,015		$	1,464,269

Pursuant to the FASB’s authoritative guidance on asset retirement obligations, net capitalized costs include asset retirement costs of $125.9 million and $104.2 million as of December 31, 2013 and 2012.

Costs Incurred

Our oil and natural gas activities are conducted in the United States. The following table summarizes the costs incurred by us for the periods indicated:


	Year Ended December 31,
	2013		2012		2011
Acquisition of oil and natural gas properties:
Evaluated	$	128,234	$	442,363	$	—
Unevaluated		—		11,500		—
Development costs		98,142		140,037		102,606

Total	$	226,376	$	593,900	$	102,606

Estimated Proved Reserves

Third Party Reserves Estimate. The reserve estimates as of December 31, 2013, 2012 and 2011 presented in the table below were based on reserve reports prepared by Netherland, Sewell & Associates, Inc. for 2013 and Miller & Lents, Ltd. for 2012 and 2011, independent reserve engineers, using FASB and SEC rules in effect as of December 31, 2013, 2012 and 2011.

Oil and Natural Gas Reserve Quantities. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made.

Prices include consideration of changes in existing prices provided only by contractual arrangement, but not on escalations based on future conditions. All of the Partnership’s oil and natural gas producing activities were conducted within the continental United States.

Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as “proved developed reserves” only after testing by a pilot project or after the operations of an installed program has confirmed through production response that the increased recovery will be achieved.

We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

F-51

Following is a summary of the proved developed and total proved oil, natural gas and NGL reserves attributed to our operations for the periods indicated:


	Oil (MBbl)			Natural Gas (MMcf)			NGL (MBbl)			Total (MBoe)

Balance, December 31, 2010		36,161			243,265			1,920			78,625
Extensions		2,002			677			211			2,325
Revisions of previous estimates		4,033			(28,461	)		6,873			6,162
Production		(2,594	)		(16,927	)		(377	)		(5,792	)

Balance, December 31, 2011		39,602			198,554			8,627			81,320

Extensions		1,877			4,958			257			2,960
Revisions of previous estimates		342			(12,643	)		1,764			(1	)
Acquisition of reserves		18,123			12,926			647			20,924
Production		(3,106	)		(13,475	)		(743	)		(6,095	)

Balance, December 31, 2012		56,838			190,320			10,552			99,110

Extensions		4,342			2,912			616			5,443
Revisions of previous estimates		8,429			(29,997	)		241			3,671
Acquisition of reserves		7,229			3			163			7,393
Production		(3,823	)		(11,497	)		(796	)		(6,535	)

Balance, December 31, 2013		73,015			151,741			10,776			109,081


Proved developed reserves:
December 31, 2011		26,649			142,428			6,842			57,229
December 31, 2012		44,487			131,700			8,125			74,562
December 31, 2013		61,492			130,201			9,505			92,696
Proved undeveloped reserves:
December 31, 2011		12,953			56,126			1,785			24,092
December 31, 2012		12,351			58,620			2,427			24,549
December 31, 2013		11,524			21,540			1,272			16,385

Our total proved reserves have increased each year since 2010. The extensions in our reserves during 2013 are primarily attributable to additional development opportunities at Jay Field resulting from updated technical analysis. The revisions in our reserves during 2013 are primarily attributable to favorable prices and enhanced performance partially offset by a reduction in PUD reserves. The acquisitions of our reserves are primarily due to the 2013 East Texas Oil Field acquisition.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day of-the-month prices for the prior 12 months were $96.91/Bbl for oil and $3.67/MMbtu for natural gas as of December 31, 2013; $94.71/Bbl for oil and $2.76/MMbtu for natural gas as of December 31, 2012; and $96.19/Bbl for oil and $4.12/MMbtu for natural gas as of December 31, 2011. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. As of December 31, 2013, the relevant average realized prices for oil, natural gas and NGLs were $101.75 per Bbl, $3.60 per Mcf and $40.36 per Bbl. As of December 31, 2012, the relevant average realized prices for oil, natural gas and NGLs were $96.86 per Bbl, $2.81 per Mcf and $42.16 per Bbl. As of December 31, 2011, the relevant average realized prices for oil, natural gas and NGLs were $93.69 per Bbl, $4.28 per Mcf and $50.00 per Bbl.

Changes in the demand for oil and natural gas, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of current market value of our proved reserves.

F-52

The estimated standardized measure of discounted future net cash flows relating to our proved reserves is shown below for the periods indicated:


	Year Ended December 31,
	2013			2012			2011
Future cash inflows	$	8,264,552		$	6,429,372		$	4,992,358
Future production and development costs		(4,108,224	)		(3,199,516	)		(2,383,342	)

Future net cash flows		4,156,328			3,229,856			2,609,016
10% annual discount for estimated timing of cash flows		(2,112,944	)		(1,623,015	)		(1,297,353	)

Standardized measure of discounted future net cash flows	$	2,043,384		$	1,606,841		$	1,311,663

The above table does not include the effects of income taxes on future net revenues because during years ended December 31, 2013, 2012 and 2011, we were not subject to federal taxation at an entity-level. Accordingly, no provision for federal tax has been provided because taxable income is passed through to the partners. State corporate income, franchise and/or gross margins taxes have not been included due to their immateriality.

The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to our proved oil, natural gas and NGL reserves for the periods indicated:


	Year Ended December 31,
	2013			2012			2011
Beginning of period	$	1,606,841		$	1,311,663		$	1,050,024
Extensions		171,240			37,262			42,940
Revisions of previous estimates		67,569			(29	)		114,354
Acquisition of reserves		170,811			484,163			—
Changes in future development costs, net		38,493			(49,392	)		(59,955	)
Development costs incurred during the year that reduce future development costs		12,146			24,352			11,994
Net change in prices		121,459			(113,366	)		261,402
Sales, net of production costs		(272,700	)		(228,039	)		(224,012	)
Changes in timing and other		(33,159	)		9,061			9,914
Accretion of discount		160,684			131,166			105,002

End of period	$	2,043,384		$	1,606,841		$	1,311,663

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly financial data was as follows for the periods indicated:


	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
2013
Revenues	$	104,886		$	105,430	$	126,007		$	119,306
Gross profit (1)		62,138			62,941		78,751			71,101
Operating income		18,934			24,363		37,173			28,433
Net income (loss)		(8,174	)		63,614		(21,497	)		27,685
Net income (loss) attributable to QR Energy, LP		(8,174	)		63,614		(21,719	)		27,244
Net income (loss) per limited partner unit (basic)	$	(0.33	)	$	0.89	$	(0.57	)	$	0.25
Net income (loss) per limited partner unit (diluted)	$	(0.33	)	$	0.77	$	(0.57	)	$	0.25

(1)	Represents total revenues less production expenses and disposal and related operating expenses.

F-53


	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
2012
Revenues	$	94,104		$	89,356	$	91,128		$	97,410
Gross profit (1)		61,337			53,212		55,980			57,531
Operating income		25,656			15,409		17,222			12,054
Net income (loss)		(8,226	)		130,700		(44,660	)		1,937
Net income (loss) per limited partner unit (basic)	$	(0.49	)	$	2.15	$	(1.25	)	$	(0.24	)
Net income (loss) per limited partner unit (diluted)	$	(0.49	)	$	1.67	$	(1.25	)	$	(0.24	)

⁽¹⁾	Represents total revenues less production expenses.

F-54

QR ENERGY, LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)


	June 30, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	6,415		$	13,360
Accounts receivable		56,116			57,442
Due from affiliates		4,380			3,915
Derivative instruments		15,065			27,485
Prepaid and other current assets		4,122			1,859

Total current assets		86,098			104,061

Noncurrent assets:
Oil and natural gas properties, using the full cost method of accounting
Evaluated		2,027,758			1,905,110
Unevaluated		3,780			4,320

Gross oil and natural gas properties		2,031,538			1,909,430
Other property, plant and equipment		15,033			14,114
Less accumulated depreciation, depletion, and amortization		(379,083	)		(318,561	)

Total oil and natural gas properties and other property, plant and equipment, net		1,667,488			1,604,983
Derivative instruments		14,265			62,131
Other assets		57,894			44,752

Total noncurrent assets		1,739,647			1,711,866

Total assets	$	1,825,745		$	1,815,927


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Current portion of asset retirement obligations	$	4,356		$	4,310
Derivative instruments		26,009			11,233
Accrued and other liabilities		78,619			79,045

Total current liabilities		108,984			94,588

Noncurrent liabilities:
Long-term debt		1,011,852			911,593
Deferred Class B unit obligation		153,749			—
Derivative instruments		19,471			6,251
Asset retirement obligations		156,447			151,011
Deferred taxes		2,352			2,114
Other liabilities		11,857			12,911

Total noncurrent liabilities		1,355,728			1,083,880

Commitments and contingencies (see Note 12)
Partners’ capital:
Class C convertible preferred unitholders (16,666,667 units issued and outstanding as of June 30, 2014 and December 31, 2013)		396,639			388,621
General partner (zero and 51,036 units issued and outstanding as of June 30, 2014 and December 31, 2013)		—			614
Class B unitholders (6,133,558 units issued and outstanding as of June 30, 2014 and December 31, 2013)		—			—
Public common unitholders (51,618,330 and 51,483,263 units issued and outstanding as of June 30, 2014 and December 31, 2013)		63,438			313,302
Affiliated common unitholders (7,145,866 units issued and outstanding as of June 30, 2014 and December 31, 2013)		(111,288	)		(76,371	)
Accumulated other comprehensive income		2,912			2,744

Total QR Energy, LP partners’ capital		351,701			628,910
Noncontrolling interest		9,332			8,549

Total partners’ capital		361,033			637,459

Total liabilities and partners’ capital	$	1,825,745		$	1,815,927

See accompanying notes to the consolidated financial statements

F-55

QR ENERGY, LP

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except per unit amounts)


	Three Months Ended						Six Months Ended
	June 30, 2014			June 30, 2013			June 30, 2014			June 30, 2013
Revenues:
Oil and natural gas sales	$	128,639		$	104,638		$	246,786		$	208,806
Disposal, processing and other		4,667			792			9,143			1,510

Total revenues		133,306			105,430			255,929			210,316

Operating Expenses:
Production expenses		50,391			42,489			97,016			85,237
Disposal and related expenses		3,714			—			7,708			—
Depreciation, depletion and amortization		30,756			26,663			60,592			57,478
Accretion of asset retirement obligations		2,179			1,758			4,313			3,490
General and administrative		9,461			10,098			19,616			20,194
Acquisition and transaction costs		651			59			4,306			620

Total operating expenses		97,152			81,067			193,551			167,019

Operating income		36,154			24,363			62,378			43,297
Other income (expense):
Gain (loss) on commodity derivative contracts, net		(65,757	)		49,523			(88,922	)		33,517
Loss on Deferred Class B unit obligation		(6,732	)		—			(11,972	)		—
Interest expense, net		(14,449	)		(10,270	)		(26,669	)		(21,323	)
Other income, net		141			—			241			—

Total other income (expense), net		(86,797	)		39,253			(127,322	)		12,194

Income (loss) before income taxes		(50,643	)		63,616			(64,944	)		55,491
Income tax (expense) benefit, net		(257	)		(2	)		(352	)		(51	)

Net income (loss)		(50,900	)		63,614			(65,296	)		55,440
Less: Net income attributable to noncontrolling interest		454			—			668			—

Net income (loss) attributable to QR Energy, LP	$	(51,354	)	$	63,614		$	(65,964	)	$	55,440

Net income (loss) attributable to QR Energy, LP per limited partner unit:
Common unitholders’ (basic)	$	(1.05	)	$	0.89		$	(3.91	)	$	0.58
Common unitholders’ (diluted)		(1.05	)		0.77			(3.91	)		0.58
Weighted average number of limited partner units outstanding:
Common units (basic)		58,764			59,556			58,697			58,455
Common units (diluted)		58,764			82,356			58,697			58,455

See accompanying notes to the consolidated financial statements

F-56

QR ENERGY, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(In thousands)


	Three Months Ended					Six Months Ended
	June 30, 2014			June 30, 2013		June 30, 2014			June 30, 2013

Net income (loss)	$	(50,900	)	$	63,614	$	(65,296	)	$	55,440
Other comprehensive income, net of tax:
Reclassification adjustment for available-for-sale securities		(4	)		—		(18	)		—
Change in fair value of available-for-sale securities (1)		318			—		391			—
Pension and postretirement benefits:
Actuarial gain (2)		(46	)		—		(90	)		—

Total other comprehensive income		268			—		283			—

Total comprehensive income (loss)		(50,632	)		63,614		(65,013	)		55,440
Less: Comprehensive income attributable to noncontrolling interest		563			—		783			—

Comprehensive income (loss) attributable to QR Energy, LP	$	(51,195	)	$	63,614	$	(65,796	)	$	55,440

(1)	Net of income taxes of $163 and $285 for the three and six months ended June 30, 2014, respectively.

(2)	Net of income taxes of $(23) and $(47) for the three and six months ended June 30, 2014, respectively.

See accompanying notes to the consolidated financial statements

F-57

QR ENERGY, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL (UNAUDITED)

(In thousands)


	Class C Convertible Preferred Unitholders			General Partner			Class B Unitholders			Limited Partners						Accumulated Other Comprehensive Income		Total QR Energy, LP Partners’ Capital			Noncontrolling Interest		Total Partners’ Capital
	Class C Convertible Preferred Unitholders			General Partner			Class B Unitholders			Public Common			Affiliated Common			Accumulated Other Comprehensive Income		Total QR Energy, LP Partners’ Capital			Noncontrolling Interest		Total Partners’ Capital
Balances - December 31, 2013	$	388,621		$	614		$	—		$	313,302		$	(76,371	)	$	2,744	$	628,910		$	8,549	$	637,459
Recognition of unit-based awards		—			—			—			3,399			—			—		3,399			—		3,399
Reduction in units to cover individuals’ tax withholding		—			—			—			(601	)		—			—		(601	)		—		(601	)
Buyout of general partner		—			(141,777	)		—			—			—			—		(141,777	)		—		(141,777	)
Distributions to unitholders		(7,000	)		(17	)		(5,919	)		(51,132	)		(6,967	)		—		(71,035	)		—		(71,035	)
Amortization of discount on increasing rate distributions		8,018			—			—			—			—			—		8,018			—		8,018
Noncash distribution to preferred unitholders		(8,018	)		—			—			—			—			—		(8,018	)		—		(8,018	)
Management incentive fee earned		—			(1,399	)		—			—			—			—		(1,399	)		—		(1,399	)
Other comprehensive income, net of tax		—			—			—			—			—			168		168			115		283
Net income (loss)		15,018			142,579			5,919			(201,530	)		(27,950	)		—		(65,964	)		668		(65,296	)

Balances - June 30, 2014	$	396,639		$	—		$	—		$	63,438		$	(111,288	)	$	2,912	$	351,701		$	9,332	$	361,033

See accompanying notes to the consolidated financial statements

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QR ENERGY, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)


	Six Months Ended
	June 30, 2014			June 30, 2013
Cash flows from operating activities:
Net income (1)	$	(65,296	)	$	55,440
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		60,592			57,478
Accretion of asset retirement obligations		4,313			3,490
Recognition of unit-based awards		3,399			3,185
Loss (gain) on derivative contracts, net		91,215			(34,205	)
Cash received (paid) on settlement of derivative contracts		(2,933	)		14,398
Loss on deferred Class B unit obligation		11,972			—
Other items		4,249			2,999
Changes in operating assets and liabilities:
Accounts receivable and other assets		(24,693	)		(14,108	)
Accounts payable and other liabilities		(3,669	)		4,542

Net cash provided by operating activities		79,149			93,219

Cash flows from investing activities:
Additions to oil and natural gas properties		(73,153	)		(39,028	)
Acquisitions		(40,434	)		(2,210	)
Proceeds from sale of available-for-sale securities		893			—
Purchases of available-for-sale securities		(436	)		—

Net cash used in investing activities		(113,130	)		(41,238	)

Cash flows from financing activities:
Proceeds from issuance of units		—			80
Management incentive fee to the general partner		(1,399	)		(748	)
Distributions to unitholders		(70,964	)		(70,752	)
Units withheld for employee payroll tax obligation		(601	)		(17	)
Proceeds from bank borrowings		123,000			15,000
Repayments on bank borrowings		(23,000	)		(5,000	)
Deferred financing costs		—			(1,826	)
Other		—			(888	)

Net cash provided by (used in) financing activities		27,036			(64,151	)

Increase (decrease) in cash		(6,945	)		(12,170	)
Cash and cash equivalents at beginning of period		13,360			31,836

Cash and cash equivalents at end of period	$	6,415		$	19,666

(1)	Includes net income attributable to noncontrolling interest

See accompanying notes to the consolidated financial statements

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QR Energy, LP

Notes to Consolidated Financial Statements (Unaudited)

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

NOTE 1 – ORGANIZATION AND OPERATIONS

QR Energy, LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed on September 20, 2010, to acquire oil and natural gas assets from our affiliated entity, QA Holdings, LP (the “Predecessor”) and other third party entities to enhance and exploit oil and gas properties. Certain of the Predecessor’s subsidiaries (collectively known as the “Fund”) include Quantum Resources A1, LP, Quantum Resources B, LP, Quantum Resources C, LP, QAB Carried WI, LP, QAC Carried WI, LP and Black Diamond Resources, LLC.

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

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

As of June 30, 2014, our ownership structure comprised a 7.5% limited partner interest in us represented by 6,133,558 Class B units held by our affiliates and former owners of QRE GP, a 29.2% limited partner interest held by the Fund, comprised of common units and all of our preferred units, and a 63.3% limited partner interest held by the public unitholders.

On July 23, 2014, we signed a definitive merger agreement with Breitburn Energy Partners, LP (“Breitburn”). The transaction has been unanimously approved by the boards of directors of Breitburn and our general partner, including the Conflicts Committee formed by our general partner’s board of directors. The transaction is expected to close in late 2014 or early 2015. Refer to Note 21 – Subsequent Events for further details.

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NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles in the United States (“U.S. GAAP”) for complete annual financial statements. During interim periods, the Partnership follows the accounting policies disclosed in its Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Annual Report”), filed with the Securities and Exchange Commission (“SEC”). The unaudited consolidated financial statements for the three and six months ended June 30, 2014 and 2013 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. The unaudited consolidated financial statements include the accounts of the Partnership, its 100% owned subsidiaries, and investments we are deemed to control. All significant intercompany transactions have been eliminated upon consolidation. Prior period amounts have been revised to conform to current period presentation. Operating results for the three and six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2014. These unaudited consolidated financial statements and other information included in this quarterly report should be read in conjunction with our consolidated financial statements and notes thereto included in our 2013 Annual Report.

Accounting Policy Updates

The accounting policies followed by the Partnership are set forth in Note 2 – Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in our 2013 Annual Report. The following addition to our policies was made during the six months ended June 30, 2014 to give effect to the GP Buyout Transaction.

Deferred Class B Unit Obligation

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

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers: Topic 606. The objective of this update is to provide guidance on how an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update is prospective and is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. We are evaluating the potential impacts this ASU will have on our disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation – Stock Compensation: Topic 718. The amendments within this update require that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. This update is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015, with earlier adoption permitted. We are evaluating the potential impacts this ASU will have on our disclosures.

NOTE 3 – ACQUISITIONS

2014 Acquisitions

During 2014, we closed several small acquisitions of oil and natural gas properties located in East Texas from private sellers for an aggregate purchase price of $43.8 million in cash, subject to customary purchase price adjustments, using funds drawn on our revolving credit facility.

2013 Acquisition

F-61

using funds drawn on our revolving credit facility. The acquisition had an effective date of June 1, 2013. The acquisition costs associated with the 2013 East Texas Acquisition were $0.4 million. In connection with the 2013 East Texas Acquisition, we assumed an estimated environmental liability of $0.5 million. Refer to Note 12 – Commitments and Contingencies for further details.

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

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


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

Net assets acquired	$	108,214

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


Assets acquired and liabilities assumed:
Current assets (1)	$	7,858
Property, plant and equipment, net		13,103
Other long term assets		16,215

Total assets		37,176

Liabilities:
Current liabilities		(1,761	)
Asset retirement obligation		(4,607	)
Pension and postretirement benefits		(12,039	)

Total liabilities		(18,407	)

Fair value of saltwater disposal company		18,769
Less: Remeasurement of previously held interest		(3,237	)
Less: Fair value of noncontrolling interest in ETSWDC		(5,956	)

Fair value of ETSWDC acquired by QR Energy, LP	$	9,576

⁽¹⁾	Includes $3.5 million of cash and cash equivalents.

Pro Forma Information

The following unaudited consolidated income statement information provides actual results for the three and six months ended June 30, 2014 and pro forma income statement information for the three and six months ended June 30, 2013, which assumes the 2013 East Texas Acquisition had occurred on January 1, 2012. 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.

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	Three Months Ended					Six Months Ended
	(Unaudited)					(Unaudited)
	June 30, 2014			June 30, 2013		June 30, 2014			June 30, 2013
	Actual			Pro Forma		Actual			Pro Forma
Total revenues	$	133,306		$	118,122	$	255,929		$	235,740
Operating income	$	36,154		$	27,246	$	62,378		$	48,932
Net income (loss) attributable to QR Energy, LP	$	(51,354	)	$	66,104	$	(65,964	)	$	60,295
Net income per unit:
Common unitholders’ (basic)	$	(1.05	)	$	0.94	$	(3.91	)	$	0.66
Common unitholders’ (diluted)	$	(1.05	)	$	0.80	$	(3.91	)	$	0.66

NOTE 4 – INVESTMENTS

As of June 30, 2014, we had the following available-for-sale investments outstanding:


			Gross		Gross
	Cost Basis		Unrealized Gains		Unrealized Losses		Fair Value
Available-for-sale securities:
Equities	$	3,596		475		40		4,031
Mutual funds		10,914		622		6		11,530
Exchange traded funds		2,924		444		—		3,368

Total for available-for-sale securities	$	17,434	$	1,541	$	46	$	18,929

As of December 31, 2013, we had the following available-for-sale investments outstanding.


			Gross		Gross
	Cost Basis		Unrealized Gains		Unrealized Losses		Fair Value
Available-for-sale securities:
Equities	$	3,647		361		41		3,967
Mutual funds		11,339		320		20		11,639
Exchange traded funds		2,924		217		1		3,140

Total for available-for-sale securities	$	17,910	$	898	$	62	$	18,746

During the six months ended June 30, 2014 we received $0.9 million in proceeds from the sale of available-for-sale securities with a realized loss of less than $0.1 million.

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

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NOTE 5 – FAIR VALUE MEASUREMENTS

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

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


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

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

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

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

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

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

Deferred Class B Unit Obligation—The Deferred Class B Unit Obligation represents consideration for the GP Buyout. The fair value of the deferred Class B unit obligation is estimated using a combination of quoted market prices and the probability of achieving operating performance related to (a) the distribution rate, (b) Distribution Coverage Ratio (as defined in our Partnership Agreement), and (c) Total Debt to EBITDAX (as defined in our Partnership Agreement )(collectively “the Class B Criteria”). The Class B Criteria represent significant unobservable inputs. The valuation methodology assumes the operating performance will be achieved within 6 years from the GP Buyout. If the Class B Criteria is not satisfactorily met within 6 years of the GP Buyout, all or a portion of the obligation may not be redeemable. If the Class B Criteria is met, we estimate that 11.6 million Class B units will be issued within 6 years and will then be valued based upon quoted market prices.

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We utilize the most observable inputs available for the valuation technique utilized. The financial assets and liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. The following table sets forth, by level within the hierarchy, the fair value of our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and December 31, 2013. All fair values reflected below have been adjusted for nonperformance risk.


As of June 30, 2014	Total		Level 1		Level 2		Level 3
Assets from commodity derivative instruments	$	29,330	$	—	$	29,330	$	—

Total assets from derivative instruments		29,330		—		29,330		—

Available for sale securities:
Equities		4,031		4,031		—		—
Mutual funds		11,530		11,530		—		—
Exchange traded funds		3,368		3,368		—		—

Total available for sale securities		18,929		18,929		—		—

	$	48,259	$	18,929	$	29,330	$	—


Liabilities from commodity derivative instruments	$	35,771	$	—	$	35,771	$	—
Liabilities from interest rate derivative instruments		9,709		—		9,709		—
Deferred Class B Unit Obligation		153,749		—		—		153,749

	$	199,229	$	—	$	45,480	$	153,749


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

Total available for sale securities		18,746		18,746		—		—

	$	108,362	$	18,746	$	89,616	$	—


Liabilities from commodity derivative instruments	$	7,093	$	—	$	7,093	$	—
Liabilities from interest rate derivative instruments		10,391		—		10,391		—

	$	17,484	$	—	$	17,484	$	—

The table below presents a reconciliation of the liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2014. There were no Level 3 instruments for the six months ended June 30, 2013. The Level 3 instruments presented in the table consists of the entitlement our former general partner owners have to receive up to an aggregate of 11.6 million Class B units.


	Six Months Ended
	June 30, 2014
Balance at beginning of period	$	—
Recognition of deferred Class B unit obligation		141,777
Changes in fair value		11,972
Transfers in and (out) of Level 3		—

Balance at end of period	$	153,749

Loss on deferred Class B unit obligation attributable to the change in fair value still held at the end of the period	$	11,972

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

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Fair Value of Other Financial Instruments

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, 2014 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy.

Derivative Premiums – The fair value of the deferred premiums on our commodity derivatives is based on the current active market LIBOR. The carrying value of the premiums as of June 30, 2014 approximates fair value based on the current LIBOR and is classified as a Level 2 input in the fair value hierarchy. Refer to Note 6 – Derivative Activities for further information on the derivative premiums.

Senior Notes – The fair value of our senior notes is measured based on inputs from quoted, unadjusted prices from over-the-counter markets for debt instruments. If the senior notes had been measured at fair value, we would classify them as Level 1 under the fair value hierarchy. The fair value of our senior notes as of June 30, 2014 was $333.6 million.

There have been no transfers between levels within the fair value measurement hierarchy during the six months ended June 30, 2014.

NOTE 6 – DERIVATIVE ACTIVITIES

Commodity Derivatives

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

During the six months ended June 30, 2014, we did not enter into any new oil swap and basis swap contracts. All existing contracts were entered into with the counterparties under our revolving credit facility.

The deferred premiums associated with certain of our oil and natural gas derivative instruments were $0.1 million and $5.0 million and are classified as accrued and other liabilities and other non-current liabilities on the consolidated balance sheet as of June 30, 2014 The deferred premiums associated with certain of our oil and natural gas derivative instruments were zero and $5.0 million and are classified as accrued and other liabilities and other non-current liabilities on the consolidated balance sheet as of December 31, 2013. These deferred premiums will be paid to the counterparty with each monthly settlement (January 2015 – December 2017) and will be recognized as an adjustment of gain (loss) on commodity derivative contracts, net.

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We hold commodity derivative contracts to manage our exposure to changes in the price of oil and natural gas related to our oil and natural gas production. As of June 30, 2014, the notional volumes of our commodity derivative contracts were:


Commodity	Index	July 1 - Dec 31, 2014			2015			2016		2017
Oil positions:
Swaps
Hedged Volume (Bbls/d)	WTI		6,709			7,356			6,293		5,547
Average price ($/Bbls)		$	95.30		$	93.74		$	90.03	$	86.23
Hedged Volume (Bbls/d)	LLS		3,000			—			—		—
Average price ($/Bbls)		$	99.62			—			—		—
Basis
Hedged Volume (Bbls/d)	WTS/WTI		2,400			—			—		—
Average price ($/Bbls)		$	(2.10	)		—			—		—
Collars
Hedged Volume (Bbls/d)	WTI		425			1,025			1,500		—
Average floor price ($/Bbls)		$	90.00		$	90.00		$	80.00		—
Average ceiling price ($/Bbls)		$	106.50		$	110.00		$	102.00		—

Natural gas positions:
Swaps
Hedged Volume (MMBtu/d)	Henry Hub		26,169			7,191			11,350		10,445
Average price ($/MMBtu)		$	6.13		$	5.34		$	4.27	$	4.47
Basis Swaps (1)
Hedged Volume (MMBtu/d)	Henry Hub		17,046			14,400			—		—
Average price ($/MMBtu)		$	(0.19	)	$	(0.19	)		—		—
Collars
Hedged Volume (MMBtu/d)	Henry Hub		4,946			18,000			630		595
Average floor price ($/MMBtu)		$	5.74		$	5.00		$	4.00	$	4.00
Average ceiling price ($/MMBtu)		$	7.51		$	7.48		$	5.55	$	6.15
Puts
Hedged Volume (MMBtu/d)	Henry Hub		—			420			11,350		10,445
Average price ($/MMBtu)			—		$	4.00		$	4.00	$	4.00

⁽¹⁾	Our natural gas basis swaps are used to hedge the differential between Henry Hub and various price points.

Interest Rate Derivatives

During the six months ended June 30, 2014, we did not enter into any new interest rate swaps. All existing contracts were entered into with various financial institutions.

F-67

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, 2014				December 31, 2013
	Asset Derivatives		Liability Derivatives		Asset Derivatives		Liability Derivatives
Commodity contracts	$	29,330	$	35,771	$	89,616	$	7,093
Interest rate contracts		—		9,709		—		10,391

	$	29,330	$	45,480	$	89,616	$	17,484


Commodity
Current	$	15,065	$	20,268	$	27,485	$	5,651
Noncurrent		14,265		15,503		62,131		1,442

	$	29,330	$	35,771	$	89,616	$	7,093

Interest
Current	$	—	$	5,741	$	—	$	5,582
Noncurrent		—		3,968		—		4,809

	$	—	$	9,709	$	—	$	10,391


Total Derivatives
Current	$	15,065	$	26,009	$	27,485	$	11,233
Noncurrent		14,265		19,471		62,131		6,251

	$	29,330	$	45,480	$	89,616	$	17,484

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


	June 30, 2014						December 31, 2013
	Asset Derivatives			Liability Derivatives			Asset Derivatives			Liability Derivatives

Gross derivatives	$	29,330		$	45,480		$	89,616		$	17,484
Netting		(12,188	)		(12,188	)		(2,960	)		(2,960	)

Net derivatives	$	17,142		$	33,292		$	86,656		$	14,524

The following table presents the impact of derivatives and their location within our consolidated statements of operations for the three and six months ended June 30, 2014 and 2013:


	Three Months Ended					Six Months Ended
	June 30, 2014			June 30, 2013		June 30, 2014			June 30, 2013
Total gains (losses):
Commodity contracts (1)	$	(65,757	)	$	49,523	$	(88,922	)	$	33,517
Interest rate swaps (2)		(1,810	)		806		(2,293	)		688

Total	$	(67,567	)	$	50,329	$	(91,215	)	$	34,205

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

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

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NOTE 7 – ASSET RETIREMENT OBLIGATIONS

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

Changes in our asset retirement obligations for the six months ended June 30, 2014 are presented in the following table:


	Six Months Ended
	June 30, 2014
Beginning of period	$	155,321
Assumed in acquisition		1,249
Divested		(186	)
Revisions to previous estimates		690
Liabilities incurred		686
Liabilities settled		(1,270	)
Accretion expense		4,313

End of period	$	160,803
Less: Current portion of asset retirement obligations		(4,356	)

Asset retirement obligations - non-current	$	156,447

NOTE 8 – ACCRUED AND OTHER LIABILITIES

As of June 30, 2014 and December 31, 2013, accrued and other liabilities consisted of the following:


	June 30, 2014		December 31, 2013
Accrued lease operating expenses	$	18,234	$	20,297
Accrued capital spending		15,820		16,316
Distributions payable		14,221		14,155
Senior notes accrued interest		11,563		11,563
Accrued production and other taxes		8,138		6,270
Gas imbalance liability		6,363		6,214
Other		4,280		4,230

Total accrued and other liabilities	$	78,619	$	79,045

NOTE 9 – PENSIONS AND POSTRETIREMENT BENEFITS

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

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


	Three Months Ended					Six Months Ended
	June 30, 2014			June 30, 2013		June 30, 2014			June 30, 2013
Qualified Pension Plan									$	—
Interest cost	$	257			—	$	514			—
Service cost		62			—		124			—
Expected return on plan assets		(337	)		—		(674	)		—

Net periodic pension cost (income)	$	(18	)	$	—	$	(36	)	$	—


Postretirement Benefits									$	—
Interest cost	$	43			—	$	86			—
Service cost		9			—		18			—
Expected return on plan assets		(24	)		—		(48	)		—
Amortization of (gain)/loss		(69	)		—		(137	)		—

Total postretirement benefit cost (income)	$	(41	)	$	—	$	(81	)	$	—

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NOTE 10 – LONG-TERM DEBT

As of June 30, 2014 and December 31, 2013, consolidated debt obligations consisted of the following:


	June 30, 2014		December 31, 2013
Senior secured revolving credit facility	$	715,000	$	615,000
9.25% Senior Notes (1)		296,852		296,593

Total long-term debt	$	1,011,852	$	911,593



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

⁽¹⁾	The amount is net of unamortized discount of $3.1 million and $3.4 million as of June 30, 2014 and December 31, 2013, respectively.

⁽²⁾	These letters of credit relate to a reclamation deposit requirement of $23.4 million and others totaling $0.1 million. Refer to Note 12 – Commitments and Contingencies for details on the reclamation deposit.

Revolving Credit Facility

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

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

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

As of June 30, 2014, we had $715.0 million of borrowings outstanding with borrowing availability of $161.5 million ($900.0 million of borrowing base less $715.0 million of outstanding borrowing and $23.5 million of letters of credit) under the Credit Agreement.

As of June 30, 2014, the Credit Agreement provided for a $1.5 billion revolving credit facility maturing on April 20, 2017, with a borrowing base of $900.0 million. The borrowing base is subject to redetermination on a semi-annual basis as of May 1 and November 1 of each year and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks’ pricing assumptions, and other various factors unique to each member bank. The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. ETSWDC and QRE GP are not subsidiary guarantors under our Credit Agreement. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum.

The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and also requires us to provide audited financial statements within 90 days of year end and quarterly unaudited financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of June 30, 2014, we were in compliance with all of the Credit Agreement covenants.

F-70

As of August 5, 2014 we had $730.0 million of borrowings outstanding with borrowing availability of $146.5 million ($900 million of borrowing base less $730.0 million of outstanding borrowing and $23.5 million of outstanding letters of credit) under the Credit Agreement.

9.25% Senior Notes

On July 30, 2012, we and our 100% owned subsidiary QRE FC, completed a private placement offering to eligible purchasers of an aggregate principal amount of $300 million of 9.25% Senior Notes, due 2020 (the “Senior Notes”). The Senior Notes were issued at 98.62% of par with interest payments to be made on February 1 and August 1 each year beginning in 2013. In 2012, we filed and completed a registration statement with the SEC to allow the holders of the Senior Notes to exchange for registered Senior Notes that have substantially identical terms as the Senior Notes. We have the option to redeem the notes, in whole or in part, at any time on or after August 1, 2016, at the specified redemption prices together with any accrued and unpaid interest to the date of redemption, except as otherwise described below. Prior to August 1, 2016, we may redeem all or any part of the notes at the “make-whole” redemption price. In addition, prior to August 1, 2015, we may at our option, redeem up to 35% of the aggregate principal amount of the notes at the redemption price with the net proceeds of a public or private equity offering. We may be required to offer to repurchase the Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Our and QRE FC’s obligations under the Senior Notes are guaranteed by OLLC. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of our, or any other guarantor’s, other, debt; or (vii) upon merging into, or transferring all of its properties to us or another guarantor and ceasing to exist. Refer to Note 20 – Subsidiary Guarantors for further details of our guarantors.

NOTE 11 – DEFERRED CLASS B UNIT OBLIGATION

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

As of June 30, 2014, the fair value of this obligation, which can only be settled through the issuance of Class B units, amounted to $153.7 million. During the period from March 2, 2014 through June 30, 2014, we recognized $12.0 million in losses attributable to the fair value change in the deferred Class B unit obligation.

NOTE 12 – COMMITMENTS AND CONTINGENCIES

Property Reclamation Deposit

As of June 30, 2014 and December 31, 2013, $10.7 million is recorded in other assets on the consolidated balance sheets related a property reclamation deposit with ExxonMobil Corporation (the “Seller”). We are required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to us until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, we have the right to request a refund of a portion or all of the property reclamation deposit. Granting of the request is at the Seller’s sole discretion. In addition to the cash deposit, a letter of credit of $23.4 million is required in favor of the Seller.

F-71

NPI Obligation

As a part of our acquisition of certain oil producing properties from the Fund in December 2012, we assumed a net profit interest (“NPI”) related to the Jay field. Under the arrangement, the NPI is payable after: (i) funds are withheld, to the extent allowable each month under the arrangement, to pay for the NPI holder’s share of future development costs and abandonment obligations, and (ii) we are reimbursed for the NPI holder’s share of excess historical productions costs. Once the NPI holder’s share of the excess historical costs is reimbursed, the NPI will be payable monthly to the extent the NPI for that month exceeds amount withheld for that month for future development costs and abandonment obligations. The NPI holder’s share of excess historical production costs amounted to $1.1 million and $2.9 million as of June 30, 2014 and December 31, 2013, respectively. In addition, we will retain the NPI holder’s shares of future development costs and abandonment obligations, subject to future production, production costs, and capital spending level, which will be paid using the funds withheld. The NPI holder’s share along with our share of the abandonment costs is reflected in our asset retirement obligations as of June 30, 2014 and December 31, 2013.

Under the arrangement, the Partnership has the option to deposit into a separate account the funds withheld from the NPI holder for their portion of the future development costs and abandonment obligations. The account for these funds was established in the second quarter of 2014 and the balance of such account as of June 30, 2014 was $18.1 million which was recorded in other assets.

Lease Guarantees

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, 2014 and December 31, 2013, we had approximately $1.8 million and $2.3 million, respectively, in environmental liabilities related to the acquisitions of oil and natural gas properties. 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.

NOTE 13 — PARTNERS’ CAPITAL

Units Outstanding

The table below details the units outstanding as of June 30, 2014 and December 31, 2013, and the changes in outstanding units for the six months ended June 30, 2014. As of June 30, 2014, the Fund owned all preferred units and all affiliated common units.


	Class C Convertible Preferred Units		General Partner			Class B Units		Public Common			Affiliated Common
Balance - December 31, 2013		16,666,667		51,036			6,133,558		51,483,263			7,145,866
Buyout of general partner		—		(51,036	)		—		—			—
Vested units awarded under our Long-Term Incentive Performance Plan		—		—			—		168,420			—
Reduction in units to cover individuals’ tax withholdings		—		—			—		(33,353	)		—

Balance - June 30, 2014		16,666,667		—			6,133,558		51,618,330			7,145,866

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

F-72

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

Class B Units

As of June 30, 2014, the QR Parties own a 7.5% limited partnership interest in us, represented by 6,133,558 Class B units. The Class B units are immediately convertible into common units at the election of the QR Parties. Class B units have all the rights of common units except for the right to vote on matters requiring specific approval by common unitholders, and are allocated income in an amount that is equal to their distributions.

Pursuant to the GP Buyout Transaction completed on March 2, 2014, the QR Parties are entitled to receive up to an aggregate of 11.6 million Class B units in up to four annual installments during the next six calendar years, beginning with respect to the year ending December 31, 2014. The QR Parties are entitled to receive an annual installment of such units with respect to any calendar year in which we pay a distribution of $0.4744 per unit with respect to each quarter, achieved a Distribution Coverage Ratio (as defined in our Partnership Agreement) for the year of at least 1.0 and achieve a Total Debt to EBITDAX (as defined in our Partnership Agreement) of no greater than 4.0 for each quarter during such year, unless any excess has been approved by the conflicts committee of our general partner. The Class B units have the same rights, preferences and privileges of our common units and are entitled to the same cash distributions per unit as our common units, except in liquidation where distributions are made in accordance with the respective capital accounts of the units and are convertible into an equal number of common units at the election of the holder. These Class B units may be issued as incentives without any corresponding increase in the cash distributions we pay to our unitholders, and any such Class B units issued to the QR Parties will not be subject to forfeiture should we fail to meet the issuance criteria in future periods.

Simultaneously with the execution of the definitive merger agreement with Breitburn on July 23, 2014, the Partnership entered into letter agreements with each of the QR Parties, each of which provides for the waiver by the respective QR Parties of its right to receive a portion of the Class B units to which it would otherwise be entitled as a result of the immediate vesting of certain Contingent Class B Units upon a Change of Control (as defined in our Partnership Agreement).

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

Allocation of Net Income (Loss)

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

Cash Distributions

Our partnership agreement, as amended, requires that within 45 days after the end of each quarter, or at the discretion of the general partner, in three equal installments within 15, 45, and 75 days following the end of each quarter, we distribute all of our available cash to preferred unitholders, in arrears, and common unitholders of record on the applicable record date, as determined by our general partner’s Board of Directors.

F-73

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


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

December 31, 2013 (1)	$	3,500	$	0.21	$	—	$	—	$	—	$	—	$	—	$	—
December 31, 2013 (2)		—		—		8		987		8,489		1,161		10,645		0.1625
December 31, 2013 (3)		—		—		8		987		8,488		1,161		10,644		0.1625
December 31, 2013 (4)		—		—		9		987		8,483		1,161		10,640		0.1625
March 31, 2014 (5)		—		—		—		987		8,483		1,162		10,632		0.1625
March 31, 2014 (6)		—		—		—		987		8,494		1,161		10,642		0.1625
March 31, 2014 (7)		3,500		—		—		981		8,619		1,161		10,761		0.1625
June 30, 2014 (8)		—		—		—		990		8,565		1,161		10,716		0.1625
June 30, 2014 (9)		—		—		—		990		8,565		1,161		10,716		0.1625

⁽¹⁾	Distributions were made within 45 days after the end of each quarter.

⁽²⁾	In December 2013, the Board of Directors approved the first monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in January 2014 to the unitholders of record as of January 13, 2014. This distribution was recorded in the fourth quarter 2013.

⁽³⁾	In January 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in February 2014 to the unitholders of record as of February 10, 2014.

⁽⁴⁾	In February 2014, the Board of Directors approved the third monthly distribution of $0.1625 per unit with respect to the fourth quarter of 2013 which was paid in March 2014 to the unitholders of record as of March 10, 2014.

⁽⁵⁾	In March 2014, the Board of Directors approved the first monthly distribution of $0.1625 per unit with respect to the first quarter of 2014 which was paid in April 2014 to the unitholders of record as of April 9, 2014.

⁽⁶⁾	In April 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the first quarter of 2014 which was paid in May 2014 to the unitholders of record as of May 8, 2014.

⁽⁷⁾	In May 2014, the Board of Directors approved the third monthly distribution of $0.1625 per unit with respect to the first quarter 2014 which was paid in June 2014 to the unitholders of record as of June 9, 2014.

⁽⁸⁾	In June 2014, the Board of Directors approved the first monthly distribution of $0.1625 per unit with respect to the second quarter of 2014 which was paid in July 2014 to the unitholders of record as of July 9, 2014. This distribution was recorded in the second quarter of 2014.

⁽⁹⁾	In July 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the second quarter of 2014 which will be paid in August 2014 to the unitholders of record as of August 7, 2014. This distribution will be recorded in the third quarter of 2014.

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

The following sets forth the calculation of net income per limited partner unit for the three and six months ended June 30, 2014 and 2013:


	Three Months Ended						Six Months Ended
	June 30, 2014			June 30, 2013			June 30, 2014			June 30, 2013
Net income (loss)	$	(50,900	)	$	63,614		$	(65,296	)	$	55,440
Net income attributable to noncontrolling interest		(454	)		—			(668	)		—

Net income attributable to QR Energy, LP		(51,354	)		63,614			(65,964	)		55,440

Distribution on Class C convertible preferred units		(3,500	)		(3,500	)		(7,000	)		(7,000	)
Amortization of preferred unit discount		(4,030	)		(3,868	)		(8,018	)		(7,697	)
Distribution on Class B units		(2,968	)		(2,990	)		(5,930	)		(5,980	)

Net income (loss) available to other unitholders		(61,852	)		53,256			(86,912	)		34,763
Less: general partners’ interest in net income		—			36			142,579			770

Limited partners’ interest in net income (loss)	$	(61,852	)	$	53,220		$	(229,491	)	$	33,993

Common unitholders’ interest in net income (loss)	$	(61,852	)	$	53,220		$	(229,491	)	$	33,993
Net income (loss) attributable to QR Energy, LP per limited partner unit:
Common unitholders’ (basic)	$	(1.05	)	$	0.89		$	(3.91	)	$	0.58
Common unitholders’ (diluted)	$	(1.05	)	$	0.77		$	(3.91	)	$	0.58
Weighted average number of limited partner units outstanding (in thousands) (1)
Common units (basic)		58,764			59,556			58,697			58,455
Common units (diluted)		58,764			82,356			58,697			58,455

⁽¹⁾

For the three and six months ended June 30, 2014 and 2013, we had weighted average preferred units outstanding of 16,666,667. The preferred and Class B units are contingently convertible into common units and could potentially dilute earnings per unit in the future. The preferred and Class B units have not been included in the diluted earnings per unit calculation for the three and six months ended June 30, 2014 and 2013, as they were anti-dilutive for the periods. For the three and six months ended June 30, 2014, we had 11.6 million Deferred Class B units which were also not included in the diluted earnings per unit calculation as they were anti-dilutive for the period.

Net income (loss) per limited partner unit is determined by dividing the net income (loss) available to the limited partner, after deducting QRE GP’s interest in net income (loss) through the date of the GP Buyout Transaction, by the weighted average number of limited partner units outstanding during the three and six months ended June 30, 2014 and 2013.

NOTE 15 – ACCUMULATED OTHER COMPREHENSIVE INCOME / (LOSS)

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


	Gains/(loss) on
	Available-For- Sale			Postretirement
	Securities			Benefits			Total
Accumulated comprehensive income as of December 31, 2013	$	613		$	4,061		$	4,674
Other comprehensive income before reclassifications		391			—			391
Amounts reclassified from accumulated other comprehensive income (1)		(18	)		(90	)		(108	)

Net current period other comprehensive income		373			(90	)		283

Accumulated comprehensive income as of June 30, 2014	$	986		$	3,971		$	4,957


Accumulated comprehensive income attributable to non-controlling interest		424			1,621			2,045

Accumulated comprehensive income attributable to QR Energy, LP	$	562		$	2,350		$	2,912

⁽¹⁾	Amounts were reclassified from accumulated other comprehensive income / (loss) into “Other income (expense), net” in the Consolidated Statement of Operations.

F-75

NOTE 16 – UNIT-BASED COMPENSATION

The QRE GP, LLC Long-Term Incentive Plan (the “Plan”) was established for employees, officers, consultants and directors of the Partnership and its affiliates, including QRM, who perform services for us. The Plan consists of unit options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the Plan is to provide additional incentive compensation to such individuals providing services to us and to align the economic interests of such individuals with the interests of our unitholders. The Plan limits the number of common units that may be delivered pursuant to awards under the Plan to 1.8 million units.

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

Restricted Units

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

On April 10, 2014, we granted approximately 550,000 Restricted Unit awards and approximately 135,000 Performance Unit awards to employees of QRM and approximately 20,000 unit awards to independent directors of the Partnership.

Service Restricted Units

For the three months ended June 30, 2014 and 2013, we recognized compensation expense related to the outstanding Restricted Units of $1.1 million and $2.0 million. For the six months ended June 30, 2014 and 2013, we recognized compensation expense related to the outstanding Restricted Units of $2.6 million and $2.9 million.

Performance Restricted Units.

The Performance Units will be earned over a three year period based on the Partnership’s performance relative to its peers in accordance with the Plan. The final units to be issued will range from 0 – 225% of the initial units granted. For the three months ended June 30, 2014 and 2013, we recognized $0.6 million and $0.2 million of compensation expense related to the Performance Units. For the six months ended June 30, 2014 and 2013, we recognized $0.8 million and $0.3 million of compensation expense related to the Performance Units.

The following table summarizes the activity of our Restricted Units and Performance Units for the six months ended June 30, 2014:


				Weighted					Weighted
	Number of			Average					Average
	Service Restricted units			Grant-Date Fair Value		Number of Performance units			Grant-Date Fair Value
Unvested units, December 31, 2013		754,822		$	18.22		267,489		$	10.17
Granted		570,274			18.00		135,208			12.33
Forfeited		(89,000	)		21.00		(18,797	)		10.22
Vested		(168,420	)		18.15		—			—

Unvested units, June 30, 2014		1,067,676		$	17.88		383,900		$	10.93

F-76

NOTE 17 – INCOME TAXES

The Company is a limited partnership for federal and state income tax purposes, with the exception of the State of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. In addition, the Company’s controlling interest in ETSWDC is subject to federal income tax. The Company recognized income tax expense for the three months ended June 30, 2014 and 2013 of less than $0.3 million and $0.1 million.

The Company recognized income tax expense for the six months ended June 30, 2014 and 2013 of less than $0.4 million and $0.1 million.

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

NOTE 18 – RELATED PARTY TRANSACTIONS

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

Through March 2, 2014, affiliates of the Fund owned 100% of QRE GP. As of June 30, 2014, the Fund owned an aggregate 29.2% limited partner interest in us represented by all of our Class C preferred units and 7,145,866 common units. In addition, former owners of QRE GP owned a 7.5% limited partner interest in us, represented by 6,133,558 Class B units.

Class C Agreement

Simultaneously with the execution of the definitive merger agreement with Breitburn, the Partnership entered into an agreement with the Fund parties which provides that, until the earlier of the consummation of the merger or the termination of the merger agreement with Breitburn in accordance with its terms, each Fund party will not convert the Class C units held by such Fund party into common units pursuant to such Fund party’s conversion rights under Section 5.12(b)(vii) of our Partnership Agreement. In addition, each Fund party agreed not to sell, transfer, assign, tender in any tender or exchange offer, pledge, encumber, hypothecate or dispose of, or to enter into any contract, option or other arrangement or understanding with respect to the sale, transfer, assignment, pledge, lien, hypothecation or other disposition of any Class C units.

Contracts with the Former Owners of QRE GP and its Affiliates

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

Services Agreement

QRM provides management and operational services for us and the Fund. In accordance with the Services Agreement, QRM is entitled to the reimbursement of general and administrative expenses based on the allocation of charges to us based on the estimated use of such services between us and the Fund. The reimbursement includes direct expenses plus an allocation of compensation costs based on employee time expended and other indirect expenses based on multiple operating metrics. If our sponsor raises additional funds in the future, the quarterly allocated costs will be further divided to include the sponsor’s additional funds as well. These fees will be included in general and administrative expenses in our consolidated statement of operations. QRM will have discretion to determine in good faith the proper allocation of the charges pursuant to the Services Agreement. Management believes this allocation methodology is a reasonable method of allocating general and administrative expenses between us and the Fund and provides for a reasonably accurate depiction of what our general and administrative expenses would be on a stand-alone basis without affiliations with the Fund or QRM. For the three months ended June 30, 2014 and 2013, we were charged $7.4 million and $7.7 million in allocated general and administrative expenses from QRM. For the six months ended June 30, 2014 and 2013, we were charged $15.0 million and $16.1 million in allocated general and administrative expenses from QRM.

F-77

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, 2014 are included below:


Net affiliate receivable as of December 31, 2013	$	3,915
Revenues and other increases		233,430
Expenditures		(186,153	)
Settlements from the Fund		(46,812	)

Net affiliate receivable as of June 30, 2014	$	4,380

As further described in Note 21 – Subsequent Events, simultaneously with the execution of the definitive merger agreement with Breitburn on July 23, 2014, Breitburn entered into a Transaction, Voting and Support Agreement with the Fund and QR Parties, which provides for, among other things, the termination of the Services Agreement.

Management Incentive Fee

Through March 2, 2014, under our partnership agreement, for each quarter for which we have paid distributions that equaled or exceeded 115% of our minimum quarterly distribution (which amount we refer to as our “Target Distribution”), or $0.4744 per unit, QRE GP was entitled to a quarterly management incentive fee subject to an adjusted operating surplus threshold as defined in the partnership agreement (“Adjusted Operating Surplus”). Pursuant to the GP Buyout Transaction completed on March 2, 2014 (see Note 1 – Organization and Operations), the management incentive fee was terminated effective for periods subsequent to December 31, 2013.

For the six months ended June 30, 2014, the management fee recognized was $1.4 million related to the fourth quarter of 2013. For the six months ended June 30, 2013, the management incentive fee recognized was $0.7 million related to the fourth quarter of 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.

Waiver of Issuance of Contingent Class B Units

Long–Term Incentive Plan

The Plan provides compensation for employees, officers, consultants and directors of the Partnership and its affiliates, including QRM, who perform services for us. As of June 30, 2014 and December 31, 2013, 1,451,576 and 1,022,311 restricted units were outstanding under the Amended LTIP and Plan, respectively. For additional discussion regarding the Plan see Note 16 – Unit-Based Compensation.

F-78

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

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

NOTE 19 – SUPPLEMENTAL CASH FLOW INFORMATION

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


	Six Months Ended
	June 30, 2014			June 30, 2013
Supplemental Cash Flow Information
Cash paid during the period for interest	$	25,834		$	22,647
Non-cash Investing and Financing Activities
Change in accrued capital expenditures		(496	)		11,565
Amortization of increasing rate distributions(1)		8,018			7,697
Recognition of deferred Class B unit obligations		141,777			—

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

NOTE 20 – SUBSIDIARY GUARANTORS

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

F-79

Condensed Consolidating Balance Sheets


	June 30, 2014
	Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non-Guarantor		Eliminations			Consolidated
Assets
Current assets
Cash	$	73	$	—	$	3,064	$	3,278	$	—		$	6,415
Accounts receivable		—		—		53,617		2,979		(480	)		56,116
Due from affiliates		201,782		—		—		—		(197,402	)		4,380
Derivative instruments		—		—		15,065		—		—			15,065
Prepaid and other current assets		—		—		3,841		281		—			4,122

Total current assets		201,855		—		75,587		6,538		(197,882	)		86,098

Noncurrent assets
Oil and natural gas properties and other property and equipment, net		—		—		1,652,732		14,756		—			1,667,488
Derivative instruments		—		—		14,265		—		—			14,265
Investment in subsidiaries		603,871		—		17,613		—		(621,484	)		—
Other assets		22,360		—		15,442		20,092		—			57,894

Total noncurrent assets		626,231		—		1,700,052		34,848		(621,484	)		1,739,647

Total assets		828,086		—		1,775,639		41,386		(819,366	)		1,825,745


Liabilities and Partners’ Capital
Current liabilities
Current portions of asset retirement obligations	$	—	$	—	$	4,356	$	—	$	—		$	4,356
Due to affiliates		—		—		197,402		—		(197,402	)		—
Derivative instruments		—		—		26,009		—		—			26,009
Accrued and other liabilities		25,784		—		51,519		1,796		(480	)		78,619

Total current liabilities		25,784		—		279,286		1,796		(197,882	)		108,984

Noncurrent liabilities
Long-term debt		296,852		—		715,000		—		—			1,011,852
Deferred Class B unit obligation		153,749		—		—		—		—			153,749
Derivative instruments		—		—		19,471		—		—			19,471
Asset retirement obligations		—		—		151,182		5,265		—			156,447
Other liabilities		—		—		6,829		7,380		—			14,209

Total noncurrent liabilities		450,601		—		892,482		12,645		—			1,355,728

Partners’ capital
QR Energy, LP partners’ capital		351,701		—		603,871		26,945		(630,816	)		351,701
Noncontrolling interest		—		—		—		—		9,332			9,332

Total partners’ capital		351,701		—		603,871		26,945		(621,484	)		361,033

Total liabilities and partners’ capital	$	828,086	$	—	$	1,775,639	$	41,386	$	(819,366	)	$	1,825,745

F-80

Condensed Consolidating Balance Sheets


	December 31, 2013
	Parent Co-Issuer		Subsidiary Co-Issuer		Guarantor		Non- Guarantor		Eliminations			Consolidated
Assets
Current assets
Cash	$	78	$	—	$	10,575	$	2,707	$	—		$	13,360
Accounts receivable		—		—		55,073		2,939		(570	)		57,442
Due from affiliates		234,746		—		—		—		(230,831	)		3,915
Derivative instruments		—		—		27,485		—		—			27,485
Prepaid and other current assets		—		—		1,718		141		—			1,859

Total current assets		234,824		—		94,851		5,787		(231,401	)		104,061

Noncurrent assets
Oil and natural gas properties and other property and equipment, net		—		—		1,591,015		13,968		—			1,604,983
Derivative instruments		—		—		62,131		—		—			62,131
Investment in subsidiaries		711,734		—		16,478		—		(728,212	)		—
Other assets		4,663		—		20,176		19,913		—			44,752

Total noncurrent assets		716,397		—		1,689,800		33,881		(728,212	)		1,711,866

Total assets	$	951,221	$	—	$	1,784,651	$	39,668	$	(959,613	)	$	1,815,927


Liabilities and Partners’ Capital
Current liabilities
Current portions of asset retirement obligations	$	—	$	—	$	4,310	$	—	$	—		$	4,310
Due to affiliates		—		—		230,831		—		(230,831	)		—
Derivative instruments		—		—		11,233		—		—			11,233
Accrued and other liabilities		25,718		—		52,100		1,797		(570	)		79,045

Total current liabilities		25,718		—		298,474		1,797		(231,401	)		94,588

Noncurrent liabilities
Long-term debt		296,593		—		615,000		—		—			911,593
Derivative instruments		—		—		6,251		—		—			6,251
Asset retirement obligations		—		—		145,893		5,118		—			151,011
Other liabilities		—		—		7,299		7,726		—			15,025

Total noncurrent liabilities		296,593		—		774,443		12,844		—			1,083,880

Partners’ capital
QR Energy, LP partners’ capital		628,910		—		711,734		25,027		(736,761	)		628,910
Noncontrolling interest		—		—		—		—		8,549			8,549

Total partners’ capital		628,910		—		711,734		25,027		(728,212	)		637,459

Total liabilities and partners’ capital	$	951,221	$	—	$	1,784,651	$	39,668	$	(959,613	)	$	1,815,927

F-81

Condensed Consolidating Statements of Operations


	Parent Co-Issuer			Subsidiary Co-Issuer		Guarantor			Non- Guarantor			Eliminations			Consolidated
Three Months Ended June 30, 2014
Total revenues	$	—		$	—	$	127,544		$	7,177		$	(1,415	)	$	133,306
Expenses
Production and disposal and related expenses		—			—		49,728			5,792			(1,415	)		54,105
Depreciation, depletion and amortization		—			—		30,656			100			—			30,756
General and administrative		1,678			—		7,783			—			—			9,461
Accretion of asset retirement obligations and acquisition and transaction costs		—			—		2,756			74			—			2,830

Total expenses		1,678			—		90,923			5,966			(1,415	)		97,152

Operating income		(1,678	)		—		36,621			1,211			—			36,154
Loss on commodity derivative contracts		—			—		(65,757	)		—			—			(65,757	)
Interest expense, net, income tax expense and other income, net		(7,244	)		—		(7,225	)		(96	)		—			(14,565	)
Loss on Deferred Class B unit obligation		(6,732	)		—		—			—			—			(6,732	)
Equity in earnings (loss)		(35,700	)		—		661			—			35,039			—

Net (loss) income		(51,354	)		—		(35,700	)		1,115			35,039			(50,900	)
Less: Net income attributable to noncontrolling interest		—			—		—			—			454			454

Net income (loss) attributable to QR Energy, LP	$	(51,354	)	$	—	$	(35,700	)	$	1,115		$	34,585		$	(51,354	)

Condensed Consolidating Statements of Operations


	Parent Co-Issuer			Subsidiary Co-Issuer		Guarantor			Non- Guarantor			Eliminations			Consolidated
Six Months Ended June 30, 2014
Total revenues	$	—		$	—	$	244,961		$	13,634		$	(2,666	)	$	255,929
Expenses
Production and disposal and related expenses		—			—		95,747			11,643			(2,666	)		104,724
Depreciation, depletion and amortization		—			—		60,391			201			—			60,592
General and administrative		3,492			—		16,124			—			—			19,616
Accretion of asset retirement obligations and acquisition and transaction costs		—			—		8,471			148			—			8,619

Total expenses		3,492			—		180,733			11,992			(2,666	)		193,551

Operating income		(3,492	)		—		64,228			1,642			—			62,378
Loss on commodity derivative contracts		—			—		(88,922	)		—			—			(88,922	)
Interest expense, net, income tax expense and other income, net		(14,488	)		—		(12,288	)		(4	)		—			(26,780	)
Loss on Deferred Class B unit obligation		(11,972	)		—		—			—			—			(11,972	)
Equity in earnings		(36,012	)		—		970			—			35,042			—

Net (loss) income		(65,964	)		—		(36,012	)		1,638			35,042			(65,296	)
Less: Net income attributable to noncontrolling interest		—			—		—			—			668			668

Net income (loss) attributable to QR Energy, LP	$	(65,964	)	$	—	$	(36,012	)	$	1,638		$	34,374		$	(65,964	)

F-82

Condensed Consolidating Statements of Comprehensive Income


	Parent Co-Issuer			Subsidiary Co-Issuer		Guarantor			Non- Guarantor			Eliminations			Consolidated
Three Months Ended June 30, 2014
Net income (loss)	$	(51,354	)	$	—	$	(35,700	)	$	1,115		$	35,039		$	(50,900	)
Other comprehensive income, net of tax:
Reclassification adjustment for avail-for-sale securities		—			—		—			(4	)		—			(4	)
Change in fair value of available-for-sale securities		187			—		187			318			(374	)		318
Pension and postretirement benefit:
Actuarial gain		(28	)		—		(28	)		(46	)		56			(46	)

Total other comprehensive income		159			—		159			268			(318	)		268

Total comprehensive income (loss)		(51,195	)		—		(35,541	)		1,383			34,721			(50,632	)
Less: Comprehensive income attributable to noncontrolling interest		—			—		—			—			563			563

Comprehensive income (loss) attributable to QR Energy, LP	$	(51,195	)	$	—	$	(35,541	)	$	1,383		$	34,158		$	(51,195	)

Condensed Consolidating Statements of Comprehensive Income


	Parent Co-Issuer			Subsidiary Co-Issuer		Guarantor			Non- Guarantor			Eliminations			Consolidated
Six Months Ended June 30, 2014
Net income (loss)	$	(65,964	)	$	—	$	(36,012	)	$	1,638		$	35,042		$	(65,296	)
Other comprehensive income, net of tax:
Reclassification adjustment for available-for-sale securities		—			—		—			(18	)		—			(18	)
Change in fair value of available-for-sale securities		221			—		221			391			(442	)		391
Pension and post retirement benefit:
Actuarial gain		(53	)		—		(53	)		(90	)		106			(90	)

Total other comprehensive income		168			—		168			283			(336	)		283

Total comprehensive income (loss)		(65,796	)		—		(35,844	)		1,921			34,706			(65,013	)
Less: Comprehensive income attributable to noncontrolling interest		—			—		—			—			783			783

Comprehensive income (loss) attributable to QR Energy, LP	$	(65,796	)	$	—	$	(35,844	)	$	1,921		$	33,923		$	(65,796	)

F-83

Condensed Consolidating Statements of Cash Flows


	Parent Co-Issuer			Subsidiary Co-Issuer		Guarantor			Non- Guarantor			Eliminations			Consolidated
Six Months Ended June 30, 2014
Net cash (used in) provided by operating activities	$	(14,566	)	$	—	$	92,612		$	1,103		$	—		$	79,149
Cash flows from investing activities
Additions to oil and natural gas properties		—			—		(72,164	)		(989	)		—			(73,153	)
Acquisitions		—			—		(40,434	)		—			—			(40,434	)
Distributions from subsidiaries		87,525			—		—			—			(87,525	)		—
Proceeds from sale of available-for-sale securities		—			—		—			893			—			893
Purchases of available-for-sale securities		—			—		—			(436	)		—			(436	)

Net cash (used in) provided by investing activities		87,525			—		(112,598	)		(532	)		(87,525	)		(113,130	)

Cash flows from financing activities
Distributions to unitholders		(70,964	)		—		—			—			—			(70,964	)
Proceeds from bank borrowings		—			—		100,000			—			—			100,000
Distributions to Parent		—			—		(87,525	)		—			87,525			—
Other		(2,000	)		—		—			—			—			(2,000	)

Net cash (used in) provided by financing activities		(72,964	)		—		12,475			—			87,525			27,036

Net increase (decrease) in cash		(5	)		—		(7,511	)		571			—			(6,945	)
Cash at beginning of period		78			—		10,575			2,707			—			13,360

Cash at end of period	$	73		$	—	$	3,064		$	3,278		$	—		$	6,415

NOTE 21 – SUBSEQUENT EVENTS

In preparing the accompanying financial statements, we have reviewed events that have occurred after June 30, 2014, through the issuance of the financial statements.

On June 27 2014, the Board of Directors approved the first monthly distribution of $0.1625 per unit with respect to the second quarter of 2014 which was paid in July 2014 to the unitholders of record as of July 9, 2014.

On July 28, 2014, the Board of Directors approved the second monthly distribution of $0.1625 per unit with respect to the first quarter of 2014 which will be paid in August 2014 to the unitholders of record as of August 7, 2014. This distribution will be recorded in the third quarter 2014.

On July 23, 2014, the Partnership entered into an Agreement and Plan of Merger dated as of July 23, 2014 (the “Merger Agreement”), by and among the Partnership, QRE GP, Breitburn, a Delaware limited partnership, Breitburn GP LLC, a Delaware limited liability company and the general partner of Breitburn, and Boom Merger Sub, LLC, a Delaware limited liability company and newly formed, wholly owned subsidiary of Breitburn (“Merger Sub”). Upon the terms and conditions set forth in the Merger Agreement, Merger Sub will be merged with and into the Partnership (the “Merger”), with the Partnership continuing as the surviving entity and as a wholly owned subsidiary of Breitburn. The Merger Agreement was approved by the board of directors of our general partner on July 23, 2014.

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Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each common unit and Class B unit of the Partnership issued and outstanding immediately prior to the Effective Time will be converted into the right to receive 0.9856 Breitburn common units (“Breitburn Units”) (such consideration, the “Unit Consideration”) or, in the case of fractional Breitburn Units, cash (without interest and rounded up to the nearest whole cent) in an amount equal to the product of (i) such fractional part of a Breitburn Unit multiplied by (ii) the average closing price for a Breitburn Unit as reported on the NASDAQ (the “NASDAQ”) for the ten consecutive full trading days ending at the close of trading on the closing date of the Merger (the “Closing Date”). In addition, at the Effective Time, each of the Class C convertible preferred units of the Partnership issued and outstanding immediately prior to the Effective Time will be converted into the right to receive cash in an amount equal to (i) $350 million divided by (ii) the number of Class C convertible preferred units outstanding immediately prior to the Effective Time. A number of Class B units issuable upon a change of control of the Partnership equal to (i) 6,748,067, minus (ii) the excess of (A) the number of performance units that vest and are settled in common units of the Partnership in connection with the Merger over (B) 383,900 will be issued and treated as outstanding Class B units and converted into the right to receive the Unit Consideration. In addition, (i) each restricted common unit that is outstanding pursuant to the Partnership’s long-term incentive plan will vest upon the Effective Time and be converted into the right to receive the Unit Consideration and (ii) immediately prior to the Effective Time each performance unit granted pursuant to the Partnership’s long-term incentive plan will vest and be settled with respect to the number of common units issuable determined based on actual attainment of the applicable performance goal(s) as of two business days prior to the Effective Time, with such resulting common units converted at the Effective Time into the right to receive the Unit Consideration.

The merger is expected to be tax free to the Partnership and tax free to the holders of common units (except to the extent of cash received in lieu of fractional Breitburn Units or any other actual or constructive distribution of cash, including as a result of any decrease in partnership liabilities pursuant to Section 752 of the Internal Revenue Code).

Simultaneously with the execution of the Merger Agreement, Breitburn entered into a Transaction, Voting and Support Agreement (the “Voting Agreement”) dated as of July 23, 2014 with the Fund and the QR Parties, which provides for, among other things (i) that the Fund and QR Parties will vote all common units, Class B units and Class C units owned by the them in favor of the Merger and the adoption of the Merger Agreement at any meeting of the Partnership’s unitholders called for such purpose and against any alternative proposal or any proposal made in opposition to adoption of the Merger Agreement and (ii) the termination of certain related party agreements, including the (a) the Services Agreement by and among the Partnership, the General Partner, QRE Operating, LLC and Quantum Resources Management, LLC dated December 22, 2010, (b) the Omnibus Agreement by and among the Partnership, General Partner, the Fund, QA Holdings, LP and QA Global GP, LLC, dated December 22, 2010 and (c) the Stakeholders’ Agreement by and among the Partnership and the Fund, dated as of September 29, 2010.

Simultaneously with the execution of the Merger Agreement, Breitburn, the Fund and the QR Parties entered into a Registration Rights Agreement (the “Registration Rights Agreement”) dated as of July 23, 2014 and effective as of the Closing Date. Among other things, pursuant to the Registration Rights Agreement, (i) no later than the 90th day following the Closing Date, Breitburn will file a shelf registration statement with the SEC to permit the public resale of the Breitburn Units received by the Fund and QR Parties as Unit Consideration, (ii) the Fund and QR Parties will have the right to participate in future underwritten public offerings of Breitburn Units and (iii) to initiate an underwritten offering of the Breitburn Units received by the Fund and QR Parties as Unit Consideration, subject to certain conditions.

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