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Press release from GlobeNewswire (a Nasdaq OMX company)

Legacy Reserves LP Announces Second Quarter 2013 Results

Monday, August 05, 2013

Legacy Reserves LP Announces Second Quarter 2013 Results

13:40 EDT Monday, August 05, 2013

MIDLAND, Texas, Aug. 5, 2013 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced second quarter results for 2013. Financial results contained herein are preliminary and subject to the final, unaudited financial statements included in Legacy's Form 10-Q to be filed on or about August 7, 2013.

A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.

 
  Three Months Ended Six Months Ended
  June 30, March 31, June 30,
  2013 2013 2013 2012
  (dollars in millions)
Production (Boe/d)  19,516  19,711  19,613  14,368
Revenue $118.4 $108.9 $227.3 $171.8
Net Income (Loss) $21.8 ($6.7) $15.0 $90.3
Adjusted EBITDA (*) $67.9 $64.4 $132.3 $96.4
Distributable Cash Flow (*) $38.8 $34.9 $73.7 $56.0
 
* Non-GAAP financial measure. Please see Adjusted EBITDA and Distributable Cash Flow table at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure.

Q2 2013 highlights include:

  • Production decreased 1% to 19,516 Boe/d, as the impact of extensive third-party plant downtime and natural gas line pressure issues in the Permian Basin was partially offset by production from new development projects in other parts of the Permian Basin and improved production in the Texas Panhandle due to relieved Q1 infrastructure issues.         
     
  • We generated $118.4 million of revenue and a record $67.9 million of Adjusted EBITDA representing increases of approximately 9% and 6%, respectively, over results in the prior quarter. A key driver of these improvements was improved oil differentials in the Permian Basin and Rocky Mountain regions.
     
  • After deducting $17.0 million of maintenance capital expenditures, we generated $38.8 million of Distributable Cash Flow or $0.68 per unit, representing an 11% increase over Q1.
     
  • We announced a $0.58 per unit quarterly distribution, marking our 11th consecutive quarterly increase and resulting in 3.6% year-over-year growth. Our quarterly distribution is covered by our Distributable Cash Flow by 1.17 times.

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "Legacy produced outstanding results during the second quarter generating record Adjusted EBITDA of $67.9 million and Distributable Cash Flow of $38.8 million. Despite third-party plant downtime in the Permian Basin that curtailed production from several of our oil-weighted properties, we produced over 19,500 Boe/d. Every quarter presents new challenges, and once again our team at Legacy handled these challenges well and produced strong results for our unitholders.  Our integration of the Concho acquisition has gone well. We continue to be very pleased with the results from these assets, which produced approximately 5,000 Boe/d during the second quarter despite plant downtime issues in the Permian.     

"While quarter-over-quarter WTI prices stayed relatively flat, our company-wide oil differential improved by approximately $9.00 per barrel during the second quarter as both the Permian and the Rockies regions improved to levels inside of their historical norms and above our expectations. We expect these differentials to be at or around normal levels for the remainder of 2013, with company-wide oil differentials of $5.25-$6.25 per barrel. Natural gas realizations during the first half of the year were negatively impacted by infrastructure issues and declining NGL prices. We currently expect second-half 2013 positive natural gas differentials of $0.90-$1.00 per Mcf.

"On the development front, we continue to be pleased with our program that is focused on oil-weighted projects in the Permian Basin. Our results from our operated Wolfberry drilling program remain solid, and we continue to participate in several attractive non-operated drilling projects, including a horizontal Bone Spring well in which we own a 50% working interest. We are excited about the second half of 2013, as our development pace will accelerate to include the drilling of two operated horizontal Bone Spring wells along with our drilling in the Wolfberry.

"We are pleased with our year-to-date acquisitions which total approximately $90 million of oil-weighted producing properties at attractive metrics. We have evaluated and are continuing to evaluate a strong pipeline of acquisitions of various sizes in all of our core areas, and hope to expand our acquisitions in the second half of the year. 

"Based on these strong financial and operational results as well as our positive outlook, we increased our distribution for the 11th consecutive quarter to $0.58 per unit, resulting in year-over-year distribution growth of 3.6%. For the quarter, we generated Distributable Cash Flow of $38.8 million or $0.68 per unit, covering our second quarter distribution by 1.17 times."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "We are very pleased with our strong financial and operational results during the second quarter. On May 28, we closed a $250 million private offering of 6.625% senior notes due in 2021. With this opportunistic financing, we were able to access unsecured long-term capital at very attractive rates that will provide us with greater liquidity to pursue our acquisition and development plans. In accordance with the provisions of our credit agreement, our borrowing base was automatically reduced from $800 million to $737.5 million upon the closing of our senior notes offering. As of August 5, we had $311 million of debt outstanding under our revolving credit facility, giving us a record of approximately $426 million of current availability.  Given this availability, our recent performance, and our expectations from our recent $90 million of acquisitions, we are looking forward to the second half of the year and executing on our objectives."

2013 Financial and Operating Results – Second Quarter Compared to First Quarter

  • Production decreased 1% to 19,516 Boe/d, as extensive third-party plant downtime and natural gas line pressure issues in the Permian Basin had a significant impact on production from several of our oil-weighted properties, including extended periods of shut-in production on some properties. This impact was partially offset by strong production from new development projects in other parts of the Permian Basin, improved natural gas production from other properties in the Permian Basin, and significantly improved production in the Texas Panhandle due to relieved Q1 infrastructure issues. We generated approximately 5,000 Boe/d of production from our Permian Basin acquisition from Concho Resources Inc. ("2012 COG Acquisition") compared to approximately 5,250 Boe/d in the first quarter. These properties continue to outperform our expectations even though production from a number of major oil-weighted properties, including our Lower Abo, Deep Rock, Fullerton and Shafter Lake properties, were significantly impacted by plant downtime during the quarter.
     
  • Average realized prices, excluding commodity derivatives settlements, were $66.66 per Boe, up 9% from $61.37 per Boe in the first quarter. Average realized oil prices increased 11% to $89.85 per Bbl from $81.11 per Bbl in the first quarter. While average West Texas Intermediate ("WTI") crude oil prices were essentially flat between the second and first quarters, crude oil differentials in the Permian Basin and Rocky Mountain regions improved significantly, resulting in improved company-wide crude oil differential of approximately $9.02 per Bbl. Most notably, with several refineries returning to production and the addition of new takeaway capacity, the Midland-to-Cushing/WTI differential decreased to approximately $0.16 per barrel in the second quarter from $7.70 per barrel in the first quarter. Average realized natural gas prices increased 11% to $4.76 per Mcf from $4.28 per Mcf in the first quarter due to an improvement in dry gas prices that was partially offset by a reduction in the positive differential to Henry Hub prices in the second quarter that reflects further curtailment of a portion of our NGL-rich natural gas production as well as lower NGL prices in the Permian Basin. Since NGLs are embedded in the value of our Permian Basin natural gas, the inclusion of a lower amount and lower prices of such NGLs had a negative effect on our average realized natural gas price. Average realized prices on our separately reported NGLs decreased 18% to $0.95 per gallon in the second quarter from $1.16 per gallon in the first quarter.   
     
  • Production expenses, excluding ad valorem taxes, increased 6% to $34.3 million ($19.29 per Boe) from $32.4 million ($18.26 per Boe) in the first quarter due to higher workover and various other expenses, including some continuing remedial workovers on the 2012 COG Acquisition properties.
     
  • Legacy's general and administrative expenses excluding unit-based/LTIP compensation expense totaled $5.7 million compared to $5.3 million in the first quarter. This was mostly attributable to the hiring of additional personnel to help us more efficiently manage our larger asset base. Legacy's total general and administrative expenses were $7.1 million compared to $6.3 million during the first quarter, as LTIP expense increased to $1.3 million in the second quarter compared to $1.0 million in the first quarter. 
     
  • Cash settlements paid on our commodity derivatives were $1.4 million compared to $2.6 million received during the first quarter. The increase in WTI crude oil prices between March and June resulted in a positive one-month lag effect of $0.5 million on our crude oil hedges. 
     
  • Total development capital expenditures were flat at $19.7 million compared to $19.7 million in the first quarter. Our development capital expenditures were primarily focused on our Wolfberry drilling program where we continue to see solid results. Other activity included attractive non-operated drilling projects in the Permian Basin including the drilling of a horizontal Bone Spring well in which we own a 50% interest, as well as various other development projects mostly in the Permian Basin. Non-operated capital expenditures accounted for approximately 37% of our total development capital for the quarter.  We expect our development pace to accelerate in the second half of 2013, including the drilling of two operated horizontal Bone Spring wells along with our drilling in the Wolfberry.

Commodity Derivatives Contracts

We have entered into the following oil and natural gas derivatives contracts, including swaps, enhanced swaps and three-way collars, to help mitigate the risk of changing commodity prices. As of August 5, 2013, we had entered into derivatives agreements to receive average NYMEX WTI crude oil and Waha, ANR-Oklahoma, and CIG-Rockies natural gas prices as summarized below starting with July 2013 through December 2018:

Crude Oil (WTI):

    Average Price
Calendar Year Volumes (Bbls) Price per Bbl Range per Bbl
July-December 2013  1,177,909 $91.80 $80.10 - $103.75
2014  1,776,264 $91.67 $87.50 - $103.75
2015  545,351 $91.98 $88.50 - $100.20
2016  228,600 $87.94 $86.30 - $99.85
2017  182,500 $84.75 $84.75

We have also entered into multiple NYMEX WTI crude oil derivative three-way collar contracts as follows:

    Average Short Average Long Average Short
Calendar Year Volumes (Bbls) Put Price Put Price Call Price
July-December 2013  631,120 $66.34 $91.56 $108.15
2014  1,453,880 $65.54 $90.73 $110.65
2015  1,308,500 $64.67 $89.67 $112.21
2016  621,300 $63.37 $88.37 $106.40
2017  72,400 $60.00 $85.00 $104.20

We have also entered into multiple crude oil derivative enhanced swap contracts as follows:

    Average Long Average Short Average Swap
Calendar Year Volumes (Bbls) Put Price Put Price Price
2015  365,000 $60.00 $80.00 $92.35
2016  183,000 $57.00 $82.00 $91.70
2017  182,500 $57.00 $82.00 $90.85
2018  127,750 $57.00 $82.00 $90.50

Additionally, we have entered into swaps for the Midland-to-Cushing/WTI crude oil differential with the following attributes:

    Average Price
Time Period Volumes (Bbls) Price per Bbl Range per Bbl
July-December 2013  1,472,000 ($1.47) $(1.25) - $(1.75)

Natural Gas (WAHA, ANR-Oklahoma and CIG-Rockies hubs):

    Average Price
Calendar Year Volumes (MMBtu) Price per MMBtu Range per MMBtu
July-December 2013  5,030,302 $4.31 $3.23 - $6.89
2014  8,271,254 $4.32 $3.61 - $6.47
2015  1,339,300 $5.65 $5.14 - $5.82
2016  219,200 $5.30 $5.30

Location and quality differentials attributable to our properties are not reflected in the above prices. The agreements provide for monthly settlement based on the difference between the agreement fixed price and the actual reference oil or natural gas index price.

Quarterly Report on Form 10-Q

Our consolidated financial statements and related footnotes will be available in our Form 10-Q for the quarter ended June 30, 2013, which will be filed on or about August 7, 2013.

Conference Call

As announced on July 22, 2013, Legacy will host an investor conference call to discuss Legacy's results on Tuesday, August 6, 2013, at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 877-266-0479. A replay of the call will be available through Tuesday, August 13, 2013, by dialing 855-859-2056 or 404-537-3406 and entering replay code 18067734. Those wishing to listen to the live or archived web cast via the Internet should go to the Investor Relations tab of our website at www.legacylp.com.  Following our prepared remarks, we will be pleased to answer questions from securities analysts and institutional portfolio managers and analysts; the complete call is open to all other interested parties on a listen-only basis.

About Legacy Reserves LP

Legacy Reserves LP is a master limited partnership headquartered in Midland, Texas, focused on the acquisition and development of oil and natural gas properties primarily located in the Permian Basin, Mid-Continent and Rocky Mountain regions of the United States. Additional information is available at www.legacylp.com.

Cautionary Statement Relevant to Forward-Looking Information

This press release contains forward-looking statements relating to our operations that are based on management's current expectations, estimates and projections about its operations. Words such as "anticipates," "expects," "intends," "plans," "targets," "projects," "believes," "seeks," "schedules," "estimated," and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: realized oil and natural gas prices; production volumes, lease operating expenses, general and administrative costs and finding and development costs; future operating results and the factors set forth under the heading "Risk Factors" in our annual and quarterly reports filed with the SEC. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, Legacy undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
         
  Three Months Ended Six Months Ended
  June 30, March 31, June 30,
  2013 2013 2013 2012
  (In thousands, except per unit data)
Revenues:        
Oil sales  $ 97,852  $ 90,357  $ 188,209  $ 141,925
Natural gas liquids (NGL) sales  3,161  3,342  6,503  7,250
Natural gas sales  17,373  15,180  32,553  22,634
Total revenues  118,386  108,879  227,265  171,809
         
Expenses:        
Oil and natural gas production  37,184  35,351  72,535  51,294
Production and other taxes  6,771  6,927  13,698  9,904
General and administrative  7,064  6,281  13,346  11,611
Depletion, depreciation, amortization and accretion  39,113  41,652  80,765  48,209
Impairment of long-lived assets  20,774  1,743  22,517  15,279
Gain on disposal of assets  (46)  (219)  (265)  (3,324)
Total expenses  110,860  91,735  202,596  132,973
Operating income  7,526  17,144  24,669  38,836
         
Other income (expense):        
Interest income  334  8  342  8
Interest expense  (11,206)  (10,692)  (21,898)  (8,971)
Equity in income of equity method investees  140  44  185  57
Realized and unrealized net gains (losses) on commodity derivatives  25,330  (13,005)  12,325  61,261
Other  (2)  7  4  (36)
Income (loss) before income taxes  22,122  (6,494)  15,627  91,155
         
Income tax expense  (368)  (211)  (578)  (824)
         
Net income (loss)  $ 21,754  $ (6,705)  $ 15,049  $ 90,331
         
Income (loss) per unit --        
basic and diluted  $ 0.38  $ (0.12)  $ 0.26  $ 1.89
         
Weighted average number of units used in computing net income (loss) per unit --      
Basic  57,246  57,077  57,162  47,826
         
Diluted  57,349  57,077  57,195  47,826
 
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(dollars in thousands)
  June 30, December 31,
  2013 2012
ASSETS    
Current assets:    
Cash and cash equivalents  $ 3,991  $ 3,509
Accounts receivable, net:    
Oil and natural gas  45,615  37,547
Joint interest owners  18,781  27,851
Other  411  551
Fair value of derivatives  8,518  15,158
Prepaid expenses and other current assets  5,081  3,294
     
Total current assets  82,397  87,910
     
Oil and natural gas properties, at cost:    
Proved oil and natural gas properties using the successful efforts method of accounting  2,192,538  2,078,961
Unproved properties  70,265  65,968
Accumulated depletion, depreciation, amortization and impairment  (659,918)  (573,003)
     
   1,602,885  1,571,926
Other property and equipment, net of accumulated depreciation and amortization of $5,281 and $4,618, respectively  3,442  2,646
Operating rights, net of amortization of $3,778 and $3,531, respectively  3,239  3,486
Fair value of derivatives  31,579  15,834
Other assets, net of amortization of $8,964 and $7,909, respectively  19,068  7,804
Investments in equity method investees  4,180  393
     
Total assets  $ 1,746,790  $ 1,689,999
     
LIABILITIES AND UNITHOLDERS' EQUITY    
Current liabilities:    
Accounts payable  $ 4,161  $ 1,822
Accrued oil and natural gas liabilities  69,824  50,162
Fair value of derivatives  8,232  10,801
Asset retirement obligation  2,338  29,501
Other  9,321  11,437
     
Total current liabilities  93,876  103,723
     
Long-term debt  852,872  775,838
Asset retirement obligation  169,313  132,682
Fair value of derivatives  3,155  5,590
Other long-term liabilities  1,857  1,886
     
Total liabilities  1,121,073  1,019,719
Commitments and contingencies    
Unitholders' equity:    
Limited partners' equity - 57,274,363 and 57,038,942 units issued and outstanding at June 30, 2013 and December 31, 2012, respectively  625,627  670,183
General partner's equity (approximately 0.03%)  90  97
     
Total unitholders' equity  625,717  670,280
     
Total liabilities and unitholders' equity  $ 1,746,790  $ 1,689,999
         
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
         
  Three Months Ended Six Months Ended
  June 30, March 31, June 30,
  2013 2013 2013 2012
  (In thousands, except per unit data)
Revenues:        
Oil sales  $ 97,852  $ 90,357  $ 188,209  $ 141,925
Natural gas liquids (NGL) sales  3,161  3,342  6,503  7,250
Natural gas sales  17,373  15,180  32,553  22,634
         
Total revenues  $ 118,386  $ 108,879  $ 227,265  $ 171,809
         
Expenses:        
Oil and natural gas production  $ 34,265  $ 32,385  $ 66,650  $ 46,859
Ad valorem taxes  2,919  2,966  5,885   4,435
Total oil and natural gas production including ad valorem taxes  $ 37,184  $ 35,351  $ 72,535  $ 51,294
         
Production and other taxes  $ 6,771  $ 6,927  $ 13,698  $ 9,904
         
General and administrative excluding LTIP  $ 5,720  $ 5,295  $ 11,017  $ 10,079
LTIP expense  1,344  986  2,329   1,532
Total general and administrative  $ 7,064  $ 6,281  $ 13,346  $ 11,611
         
Depletion, depreciation, amortization and accretion  $ 39,113  $ 41,652  $ 80,765  $ 48,209
         
Realized commodity derivative settlements:        
Realized gains (losses) on oil derivatives  $ (1,934)  $ 229  $ (1,705)  $ (13,057)
Realized gains on natural gas derivatives  $ 584  $ 2,406  $ 2,990  $ 8,967
         
Production:        
Oil (MBbls)  1,089  1,114  2,203  1,578
Natural gas liquids (MGal)  3,320  2,893  6,213  7,116
Natural gas (MMcf)  3,649  3,546  7,194  5,203
Total (MBoe)  1,776  1,774  3,550  2,615
Average daily production (Boe/d)  19,516  19,711  19,613  14,368
         
Average sales price per unit (excluding commodity derivatives):        
Oil price (per Bbl)  $ 89.85  $ 81.11  $ 85.43  $ 89.94
Natural gas liquids price (per Gal)  $ 0.95  $ 1.16  $ 1.05  $ 1.02
Natural gas price (per Mcf)  $ 4.76  $ 4.28  $ 4.53  $ 4.35
Combined (per Boe)  $ 66.66  $ 61.37  $ 64.02  $ 65.70
         
Average sales price per unit (including realized commodity derivative gains/losses):        
Oil price (per Bbl)  $ 88.08  $ 81.32  $ 84.66  $ 81.67
Natural gas liquids price (per Gal)  $ 0.95  $ 1.16  $ 1.05  $ 1.02
Natural gas price (per Mcf)  $ 4.92  $ 4.96  $ 4.94  $ 6.07
Combined (per Boe)  $ 65.90  $ 62.86  $ 64.38  $ 64.14
         
NYMEX oil index prices per Bbl:        
Beginning of Period  $ 97.23  $ 91.82  $ 91.82  $ 98.83
End of Period  $ 96.56  $ 97.23  $ 96.56  $ 84.96
         
NYMEX gas index prices per Mcf:        
Beginning of Period  $ 4.02  $ 3.35  $ 3.35  $ 2.99
End of Period  $ 3.57  $ 4.02  $ 3.57  $ 2.82
         
Average unit costs per Boe:        
Oil and natural gas production  $ 19.29  $ 18.26  $ 18.77  $ 17.92
Ad valorem taxes  $ 1.64  $ 1.67  $ 1.66  $ 1.70
Production and other taxes  $ 3.81  $ 3.90  $ 3.86  $ 3.79
General and administrative excluding LTIP  $ 3.22  $ 2.98  $ 3.10  $ 3.85
Total general and administrative  $ 3.98  $ 3.54  $ 3.76  $ 4.44
Depletion, depreciation, amortization and accretion  $ 22.02  $ 23.48  $ 22.75  $ 18.44

Non-GAAP Financial Measures

This press release, the financial tables and other supplemental information include "Adjusted EBITDA" and "Distributable Cash Flow", both of which are non-generally accepted accounting principles ("non-GAAP") measures which may be used periodically by management when discussing our financial results with investors and analysts. The following presents a reconciliation of each of these non-GAAP financial measures to their nearest comparable generally accepted accounting principles ("GAAP") measure. 

Adjusted EBITDA and Distributable Cash Flow are presented as management believes they provide additional information and metrics relative to the performance of our business, such as the cash distributions we expect to pay to our unitholders. Management believes that both Adjusted EBITDA and Distributable Cash Flow are useful to investors because these measures are used by many companies in the industry as measures of operating and financial performance, and are commonly employed by financial analysts and others to evaluate the operating and financial performance of the Partnership from period to period and to compare it with the performance of other publicly traded partnerships within the industry. Adjusted EBITDA and Distributable Cash Flow may not be comparable to a similarly titled measure of other publicly traded limited partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner. 

"Adjusted EBITDA" and "Distributable Cash Flow" should not be considered as alternatives to GAAP measures, such as net income, operating income, cash flow from operating activities, or any other GAAP measure of financial performance.  

Adjusted EBITDA is defined as net income (loss) plus:   

  • Interest expense;
  • Income taxes;
  • Depletion, depreciation, amortization and accretion;
  • Impairment of long-lived assets;
  • (Gain) loss on sale of partnership investment;
  • (Gain) loss on disposal of assets;
  • Equity in (income) loss of equity method investees;
  • Unit-based compensation expense (benefit) related to LTIP unit awards accounted for under the equity or liability methods;
  • Minimum payments earned in excess of overriding royalty interest;
  • EBITDA applicable to equity method investee; and
  • Unrealized (gains) losses on oil and natural gas derivatives.

Distributable Cash Flow is defined as Adjusted EBITDA less:

  • Cash interest expense including the accrual of interest expense related to our senior notes which is paid on a semi-annual basis;
  • Cash income taxes;
  • Cash settlements of LTIP unit awards; and
  • Maintenance capital expenditures.

The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow:

 
  Three Months Ended  Six Months Ended
  June 30, March 31, June 30,
  2013 2013 2013 2012
  (dollars in thousands)
Net income (loss)  $ 21,754  $ (6,705)  $ 15,049  $ 90,331
Plus:        
Interest expense   11,206  10,692  21,898  8,971
Income tax expense  368  211  578  824
Depletion, depreciation, amortization and accretion  39,113  41,652  80,765  48,209
Impairment of long-lived assets  20,774  1,743  22,517  15,279
Gain on sale of assets  (46)  (219)  (265)  (3,324)
Equity in income of equity method investees  (140)  (44)  (185)  (57)
Unit-based compensation expense  1,344  986  2,329  1,532
Minimum payments earned in excess of overriding royalty interest (1)  10  400  410  -- 
EBITDA applicable to equity method investee (2)  226  --   226  -- 
Unrealized (gains) losses on oil and natural gas derivatives  (26,680)  15,640  (11,040)  (65,351)
Adjusted EBITDA  $ 67,929  $ 64,356  $ 132,282  $ 96,414
         
Less:        
Cash interest expense  11,866  11,578  23,444  9,113
Cash settlements of LTIP unit awards  287  858  1,145  2,381
Maintenance capital expenditures (3)  17,000  17,000  34,000  
Total development capital expenditures         28,892
Distributable Cash Flow  $ 38,776  $ 34,920  $ 73,693  $ 56,028
 
(1) Minimum payments earned in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019. The remaining amount of the minimum payments are recognized in net income.
(2) EBITDA applicable to equity method investee is defined as the equity method investee's net income plus interest expense and depreciation.
(3) Beginning in the first quarter of 2013, Legacy began deducting only maintenance capital expenditures instead of total development capital expenditures in the computation and presentation of Distributable Cash Flow, which results in the measure of Distributable Cash Flow not being comparable to those during any prior periods.
CONTACT: Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer
(432) 689-5200

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