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Press release from GlobeNewswire (a Nasdaq OMX company)

Legacy Reserves LP Announces Third Quarter 2013 Results

Monday, November 04, 2013

Legacy Reserves LP Announces Third Quarter 2013 Results

13:44 EST Monday, November 04, 2013

MIDLAND, Texas, Nov. 4, 2013 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced third quarter 2013 results. 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 November 6, 2013.

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

 
  Three Months Ended Nine Months Ended
  September 30, June 30, September 30,
  2013 2013 2013 2012
  (dollars in millions)
Production (Boe/d)  20,043  19,516  19,755  14,504
Revenue $136.2 $118.4 $363.4 $256.0
Net Income (Loss) ($3.4) $21.8 $11.6 $66.8
Adjusted EBITDA (*) $76.2 $67.9 $208.5 $146.0
Distributable Cash Flow (*) $44.1 $38.8 $118.0 $79.7
* 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.

Q3 2013 highlights include:

  • Record production of 20,043 Boe/d, a 3% quarterly increase, as production from our acquisitions and development projects were partially offset by the impacts of third-party plant downtime and natural gas line pressure issues in the Permian Basin.         
  • Record revenue of $136.2 million and record Adjusted EBITDA of $76.2 million, representing increases of approximately 15% and 12%, respectively, over results in the prior quarter. Key drivers of these improvements were increased production, improved WTI crude oil prices and a positive one-month hedge lag effect that were partially offset by higher cash settlements paid on our commodity hedges.
  • Distributable Cash Flow of $44.1 million (or $0.77 per unit), representing a 14% increase over Q2.
  • A declared $0.585 per unit quarterly distribution, marking our 12th consecutive quarterly increase and resulting in 3.5% year-over-year growth. Our quarterly distribution is covered by our Distributable Cash Flow by 1.31 times.

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "Legacy posted record production, revenue and Adjusted EBITDA this quarter. I am proud of the tremendous job done by our employees, whose efforts to grow production, together with favorable oil prices, helped generate these outstanding results. Although we faced infrastructure issues in the Permian Basin that will likely persist in the fourth quarter, we are hopeful that these issues will be addressed by midstream providers in due time. 

"Our oil-focused drilling efforts continue to generate solid results. Our Wolfberry program is going well. Our most recent horizontal Bone Spring well, which came online in September, exceeded our expectations, and we recently completed another Bone Spring well that will be on production this month. As we announced in September, we expanded our 2013 capital budget to $100 million. Accordingly, we expect to accelerate our capital spending in the fourth quarter and are looking forward to more success.

"During 2013, we have closed 11 acquisitions of oil-weighted producing properties at attractive metrics for approximately $100 million. While the third quarter was relatively quiet on the acquisition front, we continue to evaluate acquisitions of various sizes in all of our core areas. As always, we are committed to remaining disciplined in our evaluation approach and corresponding offers. The acquisition market over the past few years has tended to be more active in the fourth quarter, so we remain hopeful of additional acquisitions in late 2013 and 2014. 

"Given our banner operational and financial results and our positive outlook, we increased our distribution for the 12th consecutive quarter to $0.585 per unit, resulting in year-over-year distribution growth of 3.5%. For the quarter, we generated Distributable Cash Flow of $44.1 million or $0.77 per unit, covering our third quarter distribution by 1.31 times." 

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "Legacy has recently made several significant accomplishments. In addition to the records Cary referenced, we opportunistically added meaningful, costless oil hedges for Q4 2013 through 2015, and in October our 20-member bank group increased our borrowing base to $800 million, providing us with approximately $490 million of availability based on current debt outstanding. These efforts not only reflect solid quarterly performance but also position us for more success in the future.

"We are thankful for the hard work of our employees and look forward to finding attractive, MLP-friendly opportunities to invest our capital and continue to grow our business."

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

  • Production increased 3% to a record 20,043 Boe/d primarily due to production from acquisitions, most notably our $66 million acquisition of Permian Basin properties that closed on June 28. In addition, we experienced positive results from several of our development projects, particularly from our most recent horizontal Bone Spring well in southeast New Mexico that initiated production in early September. These positive factors were partially offset by i) third-party plant downtime and natural gas line pressure issues in the Permian Basin that have impacted our production for the last several quarters, and ii) downtime on several wells from our $66 million Permian Basin acquisition, which is now meeting our expectations after remedial work was completed. Third-party infrastructure issues continue to impact our Permian Basin production in the fourth quarter and will very likely impact our 2014 production. We produced approximately 4,830 Boe/d from our 2012 Permian Basin acquisition from Concho Resources Inc. compared to approximately 5,000 Boe/d in the second quarter. Despite the ongoing infrastructure issues in the Permian Basin, these properties are outperforming our expectations as we have been able to partially mitigate the strong expected production declines from our Lower Abo assets through various workover and recompletion projects.     
  • Average realized prices, excluding commodity derivatives settlements, were $73.85 per Boe, up 11% from $66.66 per Boe in the second quarter. Average realized oil prices increased 14% to $102.01 per Bbl from $89.85 per Bbl in the second quarter, as average West Texas Intermediate ("WTI") crude oil prices increased approximately $11.78 per Bbl. The Midland-to-Cushing/WTI differential remained at attractive levels during the third quarter at -$0.29 per Bbl, but this differential (which is settled a month in advance) has widened to -$1.53 per Bbl for October and November 2013. We have 8,000 Bbls/d of our Midland-to-Cushing exposure financially hedged at -$1.47 per Bbl through the end of 2013. Our Rockies oil differential, which was favorable in the second and third quarters, has also been deteriorating in the fourth quarter.  Average realized natural gas prices decreased 9% to $4.34 per Mcf from $4.76 per Mcf in the second quarter due to a decline in dry natural gas prices that was partially offset by a $0.10 improvement in the positive differential to Henry Hub prices, which reflects continued curtailment of our NGL-rich natural gas production as well as low NGL prices in the Permian Basin. Average realized prices on our separately reported NGLs increased 11% to $1.05 per gallon in the third quarter from $0.95 per gallon in the second quarter.     
  • Production expenses, excluding ad valorem taxes, increased 7% to $36.7 million ($19.88 per Boe) from $34.3 million ($19.29 per Boe) in the second quarter. This increase was due to i) additional expenses associated with acquisitions and ii) higher workover and other well failure expenses of approximately $1.0 million, the bulk of which was related to our recent $66 million acquisition of properties in the Permian Basin.    
  • Legacy's general and administrative expenses excluding unit-based/Long-Term Incentive Plan ("LTIP") compensation expense totaled $6.6 million compared to $5.7 million in the second quarter. This was mostly attributable to an increase in salary and benefit expenses related to the hiring of additional personnel to manage our larger asset base. Legacy's total general and administrative expenses were $7.9 million compared to $7.1 million during the second quarter, as LTIP expense remained at approximately $1.3 million during in the third quarter. 
  • Cash settlements paid on our commodity derivatives were $6.0 million compared to $1.4 million paid during the second quarter. The increase in WTI crude oil prices between June and September resulted in a positive one-month lag effect of $1.9 million on our crude oil hedges. 
  • Total development capital expenditures increased to $26.1 million compared to $19.7 million in the second quarter. Our development capital expenditures were primarily focused on our operated Wolfberry and Bone Spring locations. We drilled two operated horizontal Bone Spring locations in southeast New Mexico this quarter. The first of these wells initiated production in early September and has produced outstanding results. The second well was recently completed and will be on production this month. In addition, our Wolfberry drilling program continues to produce solid results. Other activity included attractive operated and non-operated projects mostly in the Permian Basin. Non-operated capital expenditures accounted for approximately 18% of our total development capital for the quarter, as this percentage was lower than our typical 25% due to higher operated capital expenditures during the quarter.

New Commodity Derivatives Contracts

Since we filed our 2nd quarter Form 10-Q, we have entered into several WTI crude oil derivatives contracts, which are summarized as follows:

Swaps:

Time Period Volumes (Bbls) Price per Bbl
October-December 2013  46,000 $107.20
2014  182,500 $97.84

Three-Way Collars:

    Average Short Average Long Average Short
Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Call Price per Bbl
2014  365,000 $70.00 $95.00 $100.54

Enhanced Swaps:

    Average Short Average Swap
Time Period Volumes (Bbls) Put Price per Bbl Price per Bbl
2015  365,000 $70.00 $92.03

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 November 4, 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 October 2013 through December 2018:

Crude Oil (WTI):

 

    Average Price
Time Period Volumes (Bbls) Price per Bbl Range per Bbl
October-December 2013  620,854 $92.90 $80.10 - $107.20
2014  1,958,764 $92.24 $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
Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Call Price per Bbl
October-December 2013  315,560 $66.34 $91.56 $108.15
2014  1,818,880 $66.43 $91.58 $108.62
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
Time Period Volumes (Bbls) Put Price per Bbl Put Price per Bbl Price per Bbl
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
       
    Average Short Average Swap
Time Period Volumes (Bbls) Put Price per Bbl Price per Bbl
2015 365,000 $70.00 $92.03

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
October-December 2013  736,000 ($1.47) $(1.25) - $(1.75)

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

    Average Price
Time Period Volumes (MMBtu) Price per MMBtu Range per MMBtu
October-December 2013  2,467,851 $4.33 $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 September 30, 2013, which will be filed on or about November 6, 2013.

Conference Call

As announced on October 22, 2013, Legacy will host an investor conference call to discuss Legacy's results on Tuesday, November 5, 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, November 12, 2013, by dialing 855-859-2056 or 404-537-3406 and entering replay code 87771876. 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 Nine Months Ended
  September 30, June 30, September 30,
  2013 2013 2013 2012
  (In thousands, except per unit data)
Revenues:        
Oil sales  $ 116,396  $ 97,852  $ 304,606  $ 212,097
Natural gas liquids (NGL) sales  3,686  3,161  10,188  10,742
Natural gas sales  16,101  17,373  48,654  33,166
         
Total revenues  136,183  118,386  363,448  256,005
         
Expenses:        
Oil and natural gas production  39,701  37,184  112,236  82,023
Production and other taxes  8,385  6,771  22,083  15,040
General and administrative  7,933  7,064  21,279  18,604
Depletion, depreciation, amortization and accretion  37,717 39,113 118,482  73,042
Impairment of long-lived assets  835  20,774  23,352  22,556
(Gain) loss on disposal of assets  758  (46)  493  (3,064)
         
Total expenses  95,329  110,860  297,925  208,201
         
Operating income  40,854  7,526  65,523  47,804
         
Other income (expense):        
Interest income  227  334  568  11
Interest expense  (14,206)  (11,206)  (36,104)  (14,256)
Equity in income of equity method investees  172  140  357  87
Net gains (losses) on commodity derivatives  (30,424)  25,330  (18,098)  34,084
Other  (16)  (2)  (11)  (87)
         
Income (loss) before income taxes  (3,393)  22,122  12,235  67,643
         
Income tax expense  (29)  (368)  (608)  (878)
         
Net income (loss)  $ (3,422)  $ 21,754  $ 11,627  $ 66,765
         
Income (loss) per unit -        
basic and diluted  $ (0.06)  $ 0.38  $ 0.20  $ 1.40
         
Weighted average number of units used in         
computing net income (loss) per unit -        
Basic  57,275  57,246  57,200  47,840
Diluted  57,275  57,349  57,295  47,840
 
 
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(dollars in thousands)
  September 30, December 31,
  2013 2012
ASSETS  
Current assets:    
Cash and cash equivalents  $ 4,053  $ 3,509
Accounts receivable, net:    
Oil and natural gas  54,039  37,547
Joint interest owners  14,546  27,851
Other  435  551
Fair value of derivatives  2,765  15,158
Prepaid expenses and other current assets  4,335  3,294
Total current assets  80,173  87,910
     
Oil and natural gas properties, at cost:    
Proved oil and natural gas properties using the successful efforts method of accounting  2,220,213  2,078,961
Unproved properties  70,849  65,968
Accumulated depletion, depreciation, amortization and impairment  (696,391)  (573,003)
   1,594,671  1,571,926
     
Other property and equipment, net of accumulated depreciation and amortization of $5,622 and $4,618, respectively  3,688  2,646
Deposits on pending acquisitions  902  -- 
Operating rights, net of amortization of $3,901 and $3,531, respectively  3,116  3,486
Fair value of derivatives  19,211  15,834
Other assets, net of amortization of $9,529 and $7,909, respectively  18,499  7,804
Investments in equity method investees  4,122  393
Total assets  $ 1,724,382  $ 1,689,999
     
LIABILITIES AND UNITHOLDERS' EQUITY  
Current liabilities:    
Accounts payable  $ 6,058  $ 1,822
Accrued oil and natural gas liabilities  73,182  50,162
Fair value of derivatives  14,124  10,801
Asset retirement obligation  2,338  29,501
Other  19,076  11,437
Total current liabilities  114,778  103,723
     
Long-term debt  844,307  775,838
Asset retirement obligation  170,768  132,682
Fair value of derivatives  2,827  5,590
Other long-term liabilities  1,780  1,886
     
Total liabilities  1,134,460  1,019,719
Commitments and contingencies    
Unitholders' equity:    
Limited partners' equity - 57,279,449 and 57,038,942 units issued and outstanding at September 30, 2013 and December 31, 2012, respectively  589,833  670,183
General partner's equity (approximately 0.03%)  89  97
Total unitholders' equity  589,922  670,280
Total liabilities and unitholders' equity  $ 1,724,382  $ 1,689,999
 
 
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
 
  Three Months Ended Nine Months Ended
  September 30, June 30, September 30,
  2013 2013 2013 2012
  (In thousands, except per unit data)
Revenues:        
Oil sales  $ 116,396  $ 97,852  $ 304,606  $ 212,097
Natural gas liquids (NGL) sales  3,686  3,161  10,188  10,742
Natural gas sales  16,101  17,373  48,654  33,166
Total revenues  $ 136,183  $ 118,386  $ 363,448  $ 256,005
         
Expenses:        
Oil and natural gas production  $ 36,659  $ 34,265  $ 103,308  $ 75,067
Ad valorem taxes  3,042  2,919  8,928  6,956
Total oil and natural gas production including ad valorem taxes  $ 39,701  $ 37,184  $ 112,236  $ 82,023
Production and other taxes  $ 8,385  $ 6,771  $ 22,083  $ 15,040
General and administrative excluding LTIP  $ 6,648  $ 5,720  $ 17,665  $ 14,934
LTIP expense  1,285  1,344  3,614  3,670
Total general and administrative  $ 7,933  $ 7,064  $ 21,279  $ 18,604
Depletion, depreciation, amortization and accretion  $ 37,717  $ 39,113  $ 118,482  $ 73,042
         
Net cash settlements on commodity derivatives:        
Net cash settlements paid on oil derivatives  $ (8,006)  $ (1,934)  $ (9,711)  $ (10,948)
Net cash settlements received on natural gas derivatives  $ 2,054  $ 584  $ 5,046  $ 12,967
         
Production:        
Oil (MBbls)  1,141  1,089  3,343  2,418
Natural gas liquids (MGal)  3,527  3,320  9,740  10,938
Natural gas (MMcf)  3,714  3,649  10,909  7,774
Total (MBoe)  1,844  1,776  5,393  3,974
Average daily production (Boe/d)  20,043  19,516  19,755  14,504
         
Average sales price per unit (excluding net cash settlements on commodity derivatives):        
Oil price (per Bbl)  $ 102.01  $ 89.85  $ 91.12  $ 87.72
Natural gas liquids price (per Gal)  $ 1.05  $ 0.95  $ 1.05  $ 0.98
Natural gas price (per Mcf)  $ 4.34  $ 4.76  $ 4.46  $ 4.27
Combined (per Boe)  $ 73.85  $ 66.66  $ 67.39  $ 64.42
         
Average sales price per unit (including net cash settlements on commodity derivatives):        
Oil price (per Bbl)  $ 95.00  $ 88.08  $ 88.21  $ 83.19
Natural gas liquids price (per Gal)  $ 1.05  $ 0.95  $ 1.05  $ 0.98
Natural gas price (per Mcf)  $ 4.89  $ 4.92  $ 4.92  $ 5.93
Combined (per Boe)  $ 70.62  $ 65.90  $ 66.53  $ 64.93
         
NYMEX oil index prices per Bbl:        
Beginning of Period  $ 96.56  $ 97.23  $ 91.82  $ 98.83
End of Period  $ 102.33  $ 96.56  $ 102.33  $ 92.19
         
NYMEX natural gas index prices per Mcf:        
Beginning of Period  $ 3.57  $ 4.02  $ 3.35  $ 2.99
End of Period  $ 3.56  $ 3.57  $ 3.56  $ 3.32
         
Average unit costs per Boe:        
Oil and natural gas production  $ 19.88  $ 19.29  $ 19.16  $ 18.89
Ad valorem taxes  $ 1.65  $ 1.64  $ 1.66  $ 1.75
Production and other taxes  $ 4.55  $ 3.81  $ 4.09  $ 3.78
General and administrative excluding LTIP  $ 3.61  $ 3.22  $ 3.28  $ 3.76
Total general and administrative  $ 4.30  $ 3.98  $ 3.95  $ 4.68
Depletion, depreciation, amortization and accretion  $ 20.45  $ 22.02  $ 21.97  $ 18.38

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;
  • Net (gains) losses on commodity derivatives; and
  • Net cash settlements received (paid) on commodity 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
  • Estimated 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  Nine Months Ended
  September 30, June 30, September 30,
  2013 2013 2013 2012
  (dollars in thousands)
Net income (loss)  $ (3,422)  $ 21,754  $ 11,627  $ 66,765
Plus:        
Interest expense   14,206  11,206  36,104  14,256
Income tax expense  29  368  608  878
Depletion, depreciation, amortization and accretion  37,717  39,113  118,482  73,042
Impairment of long-lived assets  835  20,774  23,352  22,556
(Gain) loss on disposal of assets  758  (46)  493  (3,064)
Equity in income of equity method investees  (172)  (140)  (357)  (87)
Unit-based compensation expense  1,285  1,344  3,614  3,670
Minimum payments earned in excess of overriding royalty interest (1)  316  10  726  -- 
EBITDA applicable to equity method investee (2)  219  226  445  -- 
Net (gains) losses on commodity derivatives  30,424  (25,330)  18,098  (34,084)
Net cash settlements received (paid) on commodity derivatives  (5,952)  (1,350)  (4,665)  2,019
Adjusted EBITDA  $ 76,243  $ 67,929  $ 208,527  $ 145,951
         
Less:        
Cash interest expense  14,058  11,866  37,253  14,396
Cash settlements of LTIP unit awards  315  287  1,460  3,371
Estimated maintenance capital expenditures (3)  17,800  17,000  51,800  
Total development capital expenditures      --   48,457
Distributable Cash Flow  $ 44,070  $ 38,776  $ 118,014  $ 79,727
(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 estimated 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 any periods prior to 2013. The estimated amount represents a prorated portion of capital expenditures required on average per year to maintain our production on a long-term basis, generally between five and ten years.
CONTACT: Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer
(432) 689-5200

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