News Column

QR ENERGY, LP - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

August 6, 2014

The following discussion and analysis should be read in conjunction with Management's Discussion and Analysis in Part II-Item 7 of our 2013 Annual Report and the consolidated financial statements and related notes therein. Our 2013 Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations. You should also read the following discussion and analysis together with the risk factors set forth in the 2013 Annual Report and in Part I-Item 1A "Risk Factors" of this report and the "Cautionary Statement Regarding Forward-Looking Information" in this report and in our 2013 Annual Report. Overview 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, QRE GP became a 100% owned subsidiary of the Partnership. We conduct our operations through our 100% owned subsidiary QRE Operating, LLC ("OLLC"). Our 100% owned subsidiary, QRE Finance Corporation ("QRE FC"), has no material assets and was formed for the sole purpose of serving as a co-issuer of our debt securities. We also have a controlling interest in East Texas Saltwater Disposal Company ("ETSWDC"), a privately held Texas corporation. The main purpose of ETSWDC is to dispose of salt water generated as a by-product from oil production in the East Texas Oil Field. Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploitation activities or acquire properties with existing production. The amount we realize for our production depends predominately upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differential and other factors. These risk factors are mitigated by our hedging program under which we hedge approximately 65% to 85% of our current and anticipated production over the next three-to-five years. Oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. Oil and natural gas prices have increased in the last 12 months. The unweighted arithmetic average first day of-the-month prices for the prior 12 months increased to $100.27/Bbl for oil and increased to $4.10/MMbtu for natural gas as of June 30, 2014 from $96.91/Bbl for oil and $3.67/MMbtu for natural gas as of December 31, 2013. Declines in future oil and natural gas market prices could have a negative impact on our reserve value and could result in an impairment of our oil and gas properties. For example, a hypothetical 10% decrease in the 12 month average of oil prices would decrease the standardized measure of our estimated proved reserves by $359.7 million, and a hypothetical 10% decrease in the 12 month average of natural gas prices would decrease the standardized measure of our estimated reserves by $38.7 million. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success. 33

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Table of Contents Results of Operations Three Months Ended Six Months Ended June 30, 2013 June 30, 2014 (1) June 30, 2014 June 30, 2013 (1) Revenues: Oil sales $ 105,706$ 84,666$ 202,222 $ 172,741 Natural gas sales 15,018 12,592 28,858 21,445 NGL sales 7,915 7,380 15,706 14,620 Disposal, processing and other 4,667 792 9,143 1,510 Total revenue 133,306 105,430 255,929 210,316 Operating Expenses: Lease operating expenses 40,999 34,541 79,099 69,118 Production and other taxes 8,360 7,083 16,015 14,788 Processing and transportation 1,032 865 1,902 1,331 Total 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 (expense), net 141 - 241 - Total other income, net (86,797) 39,253 (127,322) 12,194 Income 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 (loss) attributable to noncontrolling interest 454 - 668 - Net income (loss) attributable to QR Energy, LP $ (51,354)$ 63,614$ (65,964) $ 55,440 Sales volume data: Oil (MBbls) 1,072 872 2,080 1,785 Natural gas (MMcf) 3,259 2,823 6,103 5,799 NGLs (MBbls) 229 228 448 420 Total (MBoe) 1,844 1,571 3,545 3,172 Average net sales volume (Boe/d) 20,264 17,264 19,586 17,525 Average sales price per unit (1): Oil (per Bbl) $ 98.61$ 97.09$ 97.22 $ 96.77 Natural gas (per Mcf) $ 4.61 $ 4.46 $ 4.73 $ 3.70 NGLs (per Bbl) $ 34.56$ 32.37$ 35.06 $ 34.81



Average unit cost per Boe: Lease operating expense $ 22.23$ 21.99$ 22.31 $

21.79



Production and other taxes $ 4.53 $ 4.51 $

4.52 $ 4.66 Depreciation, depletion and amortization $ 16.68$ 16.97$ 17.09 $ 18.12 General and administrative expenses $ 5.13 $ 6.43 $ 5.53 $ 6.37



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

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Table of Contents Results of Operations - Continued



Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

We recorded a net loss of $51.4 million for the three months ended June 30, 2014 compared to net income of $63.6 million for the three months ended June 30, 2013. The decrease in the net income is mainly due to an increase in losses on commodity derivatives and a loss on the deferred Class B unit obligation, partially offset by an increase in operating income. Revenue: Three Months Ended June 30, Increase Percentage 2014 2013 (Decrease) Change Sales Volumes: Oil (MBbls) 1,072 872 200 23% Natural gas (MMcf) 3,259 2,823 436 15% NGL (MBbl) 229 228 1 0% Total (MBoe) 1,844 1,571 273 17% Average sales prices per unit: (1) Oil (per Bbl) $ 98.61$ 97.09$ 1.52 2% Natural gas (per Mcf) (2) 4.61 4.46 0.15 3% NGL (per Bbl) 34.56 32.37 2.19 7% Total (per Boe) $ 69.76$ 66.61$ 3.15 5% Revenues: Oil sales $ 105,706$ 84,666$ 21,040 25% Natural gas sales 15,018 12,592 2,426 19% NGL sales 7,915 7,380 535 7% Disposal, processing and other 4,667 792 3,875 489% Total revenue $ 133,306$ 105,430$ 27,876 26% (1) Does not include the impact of derivative instruments. (2) Excluding the effects of change in prices on natural gas imbalances, the



average sales prices per natural gas unit were $4.58 and $3.98 for the three

months ended June 30, 2014 and 2013, respectively. Total revenue increased by $27.9 million to $133.3 million due to increased sales volumes and prices. The increase in sales volumes is primarily due to a net increase in oil and natural gas sales volumes mainly attributable to acquisitions in East Texas and improved performance at the Jay field following a turnaround to perform routine maintenance during the second quarter of 2013. The increase in revenues was also attributable to higher oil and natural gas prices due to an increase in NYMEX prices, partially offset by less favorable oil price differentials at the Jay field. The increase in disposal, processing and other revenues is attributable to the operations of the ETSWDC, which we included in our results of operations beginning in August 2013 in connection with the 2013 East Texas Acquisition. Production Expenses. Our production expenses increased by $7.9 million to $50.4 million mainly due to an increase in lease operating expenses and production and other taxes attributable to acquisitions in East Texas, as well as increased costs associated with the higher volumes for the Jay field. Disposal and Related Expenses. The disposal and related expenses of $3.7 million are attributable to the operations of ETSWDC, which we included in our results of operations beginning in August 2013 in connection with the 2013 East Texas Acquisition. Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization ("DD&A") expenses increased by $4.1 million to $30.8 million, or $16.68 per Boe, mainly due to higher production volumes as a result of acquisitions in the first quarter of 2014 and the second half of 2013, partially offset by an increase in reserve quantities.



General and Administrative Expenses. Our general and administrative and other expenses decreased by $0.6 million to $9.5 million, or $5.13 per Boe.

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Effects of Commodity Derivative Contracts. Our net loss on commodity derivative contracts increased by $115.3 million to $65.8 million. Gains and losses on commodity derivative contracts result from changes in the current and future commodity prices as compared to the fixed price of our open commodity derivative contracts. Interest Expense, net. Net interest expense increased by $4.1 million to $14.4 million mainly due to an increase in the revolving credit facility which was used to fund acquisitions.



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

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

We recorded a net loss of $66.0 million for the six months ended June 30, 2014 compared to net gain of $55.5 million for the six months ended June 30, 2013. The increase in the net loss is mainly due to an increase in losses on commodity derivatives and a loss on the deferred Class B unit obligation, partially offset by an increase in operating income. Revenue: Six Months Ended June 30, Increase Percentage 2014 2013 (Decrease) Change Sales Volumes: Oil (MBbls) 2,080 1,785 295 17% Natural Gas (MMcf) 6,103 5,799 304 5% NGL (MBbl) 448 420 28 7% Total (MBoe) 3,545 3,172 373 12% Average sales prices per unit: (1) Oil (per Bbl) $ 97.22$ 96.77$ 0.45 0% Natural gas (per Mcf) (2) 4.73 3.70 1.03 28% NGL (per Bbl) 35.06 34.81 0.25 1% Total (per Boe) $ 69.62$ 65.83$ 3.79 6% Revenues: Oil sales $ 202,222$ 172,741$ 29,481 17% Natural Gas sales 28,858 21,445 7,413 35% NGL sales 15,706 14,620 1,086 7% Disposal, processing and other 9,143 1,510 7,633 505% Total revenue $ 255,929$ 210,316$ 45,613 22% (1) Does not include the impact of derivative instruments. (2) Excluding the effects of change in prices on natural gas imbalances, the



average sales prices per natural gas unit were $4.75 and $3.62 for the six

months ended June 30, 2014 and 2013, respectively. Total revenue increased by $45.6 million to $255.9 million due to increased sales volumes and prices. The increase in sales volumes is primarily due to a net increase in oil, natural gas and NGL sales volumes mainly attributable to acquisitions in East Texas and improved performance at the Jay field following a turnaround to perform routine maintenance during the second quarter of 2013. This increase was partially offset by a decline in volumes related to downtime in certain fields. The increase in revenues was also attributable to higher oil and natural gas prices due to increase in NYMEX prices, partially offset by less favorable oil price differentials at the Jay field. The increase in disposal, processing and other revenues is attributable to the operations of the ETSWDC, which we included in our results of operations beginning in August 2013 in connection with the 2013 East Texas Acquisition. Production Expenses. Our production expenses increased by $11.8 million to $97.0 million mainly due to an increase in lease operating expenses and production and other taxes attributable to acquisitions in East Texas, as well as increased costs associated with the higher volumes for the Jay field, partially offset by lower costs in the Permian area due to improved operating efficiencies. Disposal and Related Expenses. The disposal and related expenses of $7.7 million are attributable to the operations of ETSWDC, which we included in our results of operations beginning in August 2013 in connection with the 2013 East Texas Acquisition. 36

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Table of Contents Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization ("DD&A") expenses increased by $3.1 million to $60.6 million, or $17.09 per Boe, mainly due to higher production volumes as a result of acquisitions in the first quarter of 2014 and the second half of 2013, partially offset by an increase in reserve quantities.



General and Administrative Expenses. Our general and administrative and other expenses decreased by $0.6 million to $19.6 million, or $5.53 per Boe.

Effects of Commodity Derivative Contracts. Our net loss on commodity derivative contracts increased by $122.4 million to $88.9 million. Gains and losses on commodity derivative contracts result from changes in the current and future commodity prices as compared to the fixed price of our open commodity derivative contracts. Interest Expense, net. Net interest expense increased by $5.4 million to $26.7 million mainly due to an increase in the revolving credit facility which was used to fund acquisitions.



Other income, net. Other income of $0.2 million is mainly attributable to investment income for ETSWDC which was acquired in August 2013 in connection with the 2013 East Texas Acquisition.

Liquidity and Capital Resources

Our cash flow from operating activities for the six months ended June 30, 2014 was $79.1 million.

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under our credit facility, and debt and equity offerings. The capital markets are subject to volatility. Our exposure to current credit conditions includes our credit facility, debt securities, cash investments and counterparty performance risks. Volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. As of June 30, 2014, our cash and cash equivalents were $6.4 million, which includes $3.3 million that is held with a subsidiary that is not wholly-owned. As of June 30, 2014, our liquidity of $167.9 million consisted of $6.4 million of available cash and $161.5 million of availability under our credit facility after giving effect to $23.5 million of outstanding letters of credit. As of June 30, 2014, we had $715.0 million of borrowings outstanding. 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 our credit facility. The borrowing base is redetermined as of May 1 and November 1 of each year. Pursuant to the semi-annual borrowing base redeterminations, the borrowing base of our revolving credit facility was increased to $950 million on October 15, 2013 and reduced to $900 million on April 21, 2014. In addition, we may request additional capacity for acquisitions of a minimum of the lesser of $50 million or 10% of the then-existing borrowing base. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility. A portion of our capital resources may be utilized in the form of letters of credit to satisfy counterparty collateral demands up to $30 million. As of June 30, 2014, we had letters of credit in the amount of $23.5 million outstanding primarily related to a property reclamation deposit. Refer to Part I, Item 1. Consolidated Financial Statements - Note 12, Commitments and Contingencies for details. Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we sell and the operating and capital expenditures we incur. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors. We believe our cash flows provided by operating activities will be sufficient to meet our operating requirements for the next 12 months.



As of June 30, 2014, we had a negative working capital balance of $22.9 million.

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Table of Contents Capital Expenditures Growth capital expenditures are capital expenditures that are expected to increase our production and the size of our asset base. The primary purpose of growth capital is to acquire producing assets that will increase our distributions per unit and secondarily increase the rate of production of our existing properties in a manner which is expected to be accretive to our unitholders. We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisitions of oil and natural gas properties in 2014 through a combination of cash, borrowings under our credit facility and the issuance of debt and equity securities. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. Although we closed an acquisition in August 2013 and January 2014, as discussed in Part I, Item 1. Consolidated Financial Statements - Note 3, Acquisitions, we cannot estimate further growth capital expenditures related to acquisitions, including potential acquisitions of producing properties from the Fund, as we cannot be certain that we will be able to identify attractive properties or, if identified, that we will be able to negotiate acceptable purchase contracts. Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base. The primary purpose of maintenance capital is to maintain our production and asset base at a steady level over the long-term in order to maintain our distributions per unit. For 2014, we have estimated our maintenance capital expenditures to be approximately $72 million. During the six months ended June 30, 2014, we expended $72.7 million of capital expenditures. We currently expect 2014 total capital spending for the growth and maintenance of our oil and natural gas properties to be approximately $182.3 million. We have increased our expected capital spending to pursue growth opportunities in our various operating areas through drilling wells and recompleting or reactivating existing wells. The amount and timing of our capital expenditures is largely discretionary and within our control, with the exception of certain projects managed by other operators. If oil and natural gas prices decline below levels we deem acceptable, we may defer a portion of our planned capital expenditures until later periods. Accordingly, we routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside of our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and labor crews. Based on our current oil and natural gas price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for the remainder of 2014. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures. Credit Facility Revolving Credit Facility As of June 30, 2014, we had $715.0 million of borrowings outstanding under our revolving credit facility and $23.5 million of letters of credit outstanding resulting in $161.5 million of borrowing availability. As of June 30, 2014, we were party to the Credit Agreement through April 2017 that governs our $1.5 billion revolving credit facility with a borrowing base of $900.0 million. The borrowing base is subject to redetermination on a semi-annual basis and is subject to a number of factors including quantities of proved oil and natural gas reserves, the banks' price assumptions, and other various factors unique to each member bank. The borrowing base may also be reduced by an amount equal to 0.25 multiplied by the stated principal amount of any issuances of senior notes. In the future, we may be unable to access sufficient capital under our new credit facility as a result of (i) a decrease in our borrowing base due to subsequent borrowing base redeterminations, or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations. A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge additional oil and natural gas properties as collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the Credit Agreement. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under the Credit Agreement. 38

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Borrowings under the Credit Agreement are collateralized by liens on at least 80% of our oil and natural gas properties and all of our equity interests in OLLC and any future guarantor subsidiaries. ETSWDC and QRE GP are not subsidiary guarantors under our Credit Agreement. Borrowings bear interest at our option of either (i) the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, or the one-month adjusted LIBOR plus 1.0%, all of which would be subject to a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base is subject to a commitment fee ranging from 0.375% to 0.50% per annum. The Credit Agreement requires us to maintain a ratio of total debt to EBITDAX (as such term is defined in the Credit Agreement) of not more than 4.0 to 1.0 and a current ratio (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0. Additionally, the Credit Agreement contains various covenants and restrictive provisions which limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; prepay certain indebtedness; and to provide audited financial statements within 90 days of year end and quarterly unaudited financial statements within 45 days of quarter end. The Credit Agreement also prohibits us from entering into commodity derivative contracts covering, in any given year, in excess of the greater of (i) 90% of our forecasted production attributable to proved developed producing reserves and (ii) 85% of our forecasted production for the next two years from total proved reserves and 75% of our forecasted production from total proved reserves thereafter, in each case, based upon production estimates in the most recent reserve report. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the Credit Agreement, together with accrued interest, could be declared immediately due and payable. As of June 30, 2014, we were in compliance with all of the Credit Agreement covenants. On March 2, 2014, we entered into the sixth amendment to the Credit Agreement, which permitted the GP Buyout Transaction and provided for the exclusion of QRE GP as a guarantor of our credit facility.



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

As of August 5, 2014 we had $730.0 million of borrowings outstanding under our revolving credit facility and $146.5 million of borrowing availability.

Commodity Derivative Contracts

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil and natural gas prices. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on the prices of oil and natural gas and our ability to maintain and increase production through acquisitions and exploitation and development projects. For further discussion of our derivative activities, see Part I, Item 1. Consolidated Financial Statements - Note 6, Derivative Activities. Cash Flows Cash flows provided or used by type of activity were as follows for the periods indicated: Six Months Ended June 30, 2014 June 30, 2013 Net cash provided by (used in): Operating activities $ 79,149$ 93,219 Investing activities (113,130) (41,238) Financing activities 27,036 (64,151) Operating Activities Our cash flow from operating activities decreased by $14.1 million to $79.1 million mainly due to changes in working capital attributable to the timing of capital activities and the funding of the deposit account for the NPI related to the Jay field, partially offset by higher operating margins. 39

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Table of Contents Investing Activities



Our cash flow used in investing activities increased by $71.9 million to $113.1 million mainly due to acquisition expenditures and additions to our oil and natural gas properties related to the expansion of our capital program .

Financing Activities



Our cash flow from financing activities increased by $91.2 million to $27.0 million mainly due to borrowings under our credit facility to fund acquisitions and our capital program.

Contractual Obligations There were no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements as of June 30, 2014. Our level of capital expenditures will vary in the future periods depending on the success we experience in our acquisition, development and exploitation activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.



Off-Balance Sheet Arrangements

As of June 30, 2014, we have no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with U.S. GAAP. Preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no material changes to our critical accounting policies from those described in our 2013 Annual Report during the six months ended June 30, 2014, except for those discussed in Part I, Item 1. Consolidated Financial Statements - Note 2 - Significant Accounting Policies.



Recent Accounting Pronouncements

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

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



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

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

contracts;

Depreciation, depletion, and amortization;

Accretion of asset retirement obligations;

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

Gains or losses on commodity derivative contracts, net; Gains or losses on deferred Class B unit obligation



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

Income tax expense or benefit; Other income or expense; Interest expense; Impairments;



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

costs; 40

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Non-cash pension and postretirement expense or credit; and

Beginning with third quarter 2013, noncontrolling interest amounts attributable

to each of the items above, as applicable, which revert the calculation back to

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



the cash flow generated by our assets, without regard to financing methods,

capital structure or historical cost basis; and

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

support our indebtedness.



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

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of other companies because they may not calculate Adjusted EBITDA in the same manner. Distributable Cash Flow We define Distributable Cash Flow as Adjusted EBITDA less cash interest expense, estimated maintenance capital expenditures, distributions to preferred unitholders, and the management incentive fee as applicable to the periods prior to the GP Buyout Transaction. Estimated maintenance capital expenditures are calculated based on our estimate of the capital required to maintain our current production for five years, on average. This estimate is made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. Distributable Cash Flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserve by our general partner) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable Cash Flow is also an important financial measure for our unitholders as it serves as an indicator of our success in providing a cash return on investment. Specifically, Distributable Cash Flow indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable Cash Flow is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the yield is based on the amount of cash distributions the entity pays to a unitholder compared to its unit price. Distributable Cash Flow may not be comparable to similarly titled measures of other companies because they may not calculate Distributable Cash Flow in the same manner.



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

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Table of Contents Three Months Ended Six Months Ended June 30, 2014 June 30, 2013 June 30, 2014 June 30, 2013 Reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow: Net income $ (50,900)$ 63,614$ (65,296)$ 55,440 Loss (gain) on commodity derivative contracts, net 65,757 (49,523) 88,922 (33,517) Cash received (paid) to settle commodity derivative contracts, net (1,164) 7,435 42 16,745 Loss on Deferred Class B unit obligation 6,732 - 11,972 - Loss (gain) on effect of change in prices on gas imbalances (101) (1,365) 149 (439) Depletion, depreciation and amortization 30,756 26,663 60,592 57,478 Accretion of asset retirement obligations 2,179 1,758 4,313 3,490 Interest (income) expense 14,449 10,270 26,669 21,323 Other (income) expense (141) - (241) - Income tax expense (benefit) 257 2 352 51 Non-cash general and administrative expenses and acquisition and transaction costs 2,307 2,219 7,705 3,806 Noncontrolling interest (564) - (811) - Adjusted EBITDA $ 69,567$ 61,073 $



134,368 $ 124,377

Cash interest expense (13,211) (11,494) (25,599) (22,571) Estimated maintenance capital expenditures (18,000) (17,000) (36,000) (34,000) Distributions to preferred unitholders (3,500) (3,500) (7,000) (7,000) Management incentive fee (1) - (1,266) - (1,266) Distributable Cash Flow $ 34,856$ 27,813$ 65,769$ 59,540



(1) The management incentive fee was not applicable to the three and six months

ended June 30, 2014 as a result of the GP Buyout Transaction. The management

incentive fee applicable to the three months ended June 30, 2013 was recognized during the three months ended September 30, 2013. The increase in Adjusted EBITDA of $8.5 million to $69.6 million for the three months ended June 30, 2014 is mainly due to an increase in cash operating margins, partially offset by a decrease in cash receipts on settlements of commodity derivative contracts. The increase in Adjusted EBITDA of $ 10.0 million to $134.4 million for the six months ended June 30, 2014 is mainly due to an increase in cash operating margins, partially offset by a decrease in cash receipts on settlements of commodity derivative contracts. The increase in Distributable Cash Flow of $7.0 million to $34.9 million for the three months ended June 30, 2014 is mainly due to an increase in Adjusted EBITDA, partially offset by an increase in cash interest expense which is mainly attributable to our revolving credit facility, and an increase in maintenance capital expenditures. The increase in Distributable Cash Flow of $6.2 million to $65.8 million for the six months ended June 30, 2014 is mainly due to an increase in Adjusted EBITDA, partially offset by an increase in cash interest expense which is mainly attributable to our revolving credit facility, and an increase in maintenance capital expenditures.


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Source: Edgar Glimpses


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