Legacy Reserves LP Announces Third Quarter 2013 Results

Legacy Reserves LP Announces Third Quarter 2013 Results

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 12^th
    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 thatwill 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 12^th 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 andwill 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 2^nd 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    Call Price per
                                             Bbl              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 Put Price per Call Price
                                     Bbl           Bbl           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,         37,717       39,113    118,482    73,042
amortization and accretion
Impairment of long-lived assets  835          20,774   23,352    22,556
(Gain) loss on disposal of       758          (46)     493       (3,064)
assets
                                                                
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       172          140      357       87
method investees
Net gains (losses) on commodity  (30,424)     25,330   (18,098)  34,084
derivatives
Other                            (16)         (2)      (11)      (87)
                                                                
Income (loss) before income      (3,393)      22,122   12,235    67,643
taxes
                                                                
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     2,220,213    2,078,961
successful efforts method of accounting
Unproved properties                                 70,849       65,968
Accumulated depletion, depreciation, amortization   (696,391)    (573,003)
and impairment
                                                   1,594,671    1,571,926
                                                                
Other property and equipment, net of accumulated
depreciation and amortization of $5,622 and $4,618, 3,688        2,646
respectively
Deposits on pending acquisitions                    902          --
Operating rights, net of amortization of $3,901 and 3,116        3,486
$3,531, respectively
Fair value of derivatives                           19,211       15,834
Other assets, net of amortization of $9,529 and     18,499       7,804
$7,909, respectively
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 andoutstanding at          589,833      670,183
September 30, 2013 and December 31, 2012,
respectively
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)      3,686        3,161     10,188    10,742
sales
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        $39,701     $37,184  $112,236 $82,023
valorem taxes
Production and other taxes     $8,385      $6,771   $22,083  $15,040
General and administrative     $6,648      $5,720   $17,665  $14,934
excluding LTIP
LTIP expense                   1,285        1,344     3,614     3,670
Total general and              $7,933      $7,064   $21,279  $18,604
administrative
Depletion, depreciation,       $37,717     $39,113  $118,482 $73,042
amortization and accretion
                                                               
Net cash settlements on                                         
commodity derivatives:
Net cash settlements paid on   $(8,006)    $(1,934) $(9,711) $(10,948)
oil derivatives
Net cash settlements received  $2,054      $584     $5,046   $12,967
on natural gas derivatives
                                                               
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       20,043       19,516    19,755    14,504
(Boe/d)
                                                               
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 $1.05       $0.95    $1.05    $0.98
Gal)
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 $1.05       $0.95    $1.05    $0.98
Gal)
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     $3.61       $3.22    $3.28    $3.76
excluding LTIP
Total general and              $4.30       $3.98    $3.95    $4.68
administrative
Depletion, depreciation,       $20.45      $22.02   $21.97   $18.38
amortization and accretion

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 MonthsEnded          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,           37,717          39,113     118,482     73,042
amortization and
accretion
Impairment of           835             20,774     23,352      22,556
long-lived assets
(Gain) loss on disposal 758             (46)       493         (3,064)
of assets
Equity in income of     (172)           (140)      (357)       (87)
equity method investees
Unit-based compensation 1,285           1,344      3,614       3,670
expense
Minimum payments earned
in excess of overriding 316             10         726         --
royalty interest ^(1)
EBITDA applicable to
equity method investee  219             226        445         --
^(2)
Net (gains) losses on   30,424          (25,330)   18,098      (34,084)
commodity derivatives
Net cash settlements
received (paid) on      (5,952)         (1,350)    (4,665)     2,019
commodity derivatives
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     315             287        1,460       3,371
LTIP unit awards
Estimated maintenance
capital expenditures    17,800          17,000     51,800      
^(3)
Total development                                  --         48,457
capital expenditures
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 ofDistributable Cash Flow not being comparable
to any periods prior to 2013.The estimated amount represents a prorated
portion ofcapital expenditures required on average per year to maintain our
production on a long-term basis, generally betweenfive and ten years.

CONTACT: Legacy Reserves LP
         Dan Westcott
         Executive Vice President and Chief Financial Officer
         (432) 689-5200

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