Legacy Reserves LP Announces Second Quarter 2013 Results

Legacy Reserves LP Announces Second Quarter 2013 Results

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 11^th
    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 11^th 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,            39,113   41,652    80,765    48,209
amortization and accretion
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   140      44        185       57
investees
Realized and unrealized net gains   25,330   (13,005)  12,325    61,261
(losses) on commodity derivatives
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      2,192,538   2,078,961
successful efforts method of accounting
Unproved properties                                  70,265      65,968
Accumulated depletion, depreciation, amortization    (659,918)   (573,003)
and impairment
                                                                
                                                    1,602,885   1,571,926
Other property and equipment, net of accumulated
depreciation and amortization of $5,281 and $4,618,  3,442       2,646
respectively
Operating rights, net of amortization of $3,778 and  3,239       3,486
$3,531, respectively
Fair value of derivatives                            31,579      15,834
Other assets, net of amortization of $8,964 and      19,068      7,804
$7,909, respectively
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    625,627     670,183
December 31, 2012, respectively
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   $37,184  $35,351  $72,535  $51,294
taxes
                                                               
Production and other taxes        $6,771   $6,927   $13,698  $9,904
                                                               
General and administrative        $5,720   $5,295   $11,017  $10,079
excluding LTIP
LTIP expense                      1,344     986       2,329     1,532
Total general and administrative  $7,064   $6,281   $13,346  $11,611
                                                               
Depletion, depreciation,          $39,113  $41,652  $80,765  $48,209
amortization and accretion
                                                               
Realized commodity derivative                                   
settlements:
Realized gains (losses) on oil    $(1,934) $229     $(1,705) $(13,057)
derivatives
Realized gains on natural gas     $584     $2,406   $2,990   $8,967
derivatives
                                                               
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    $0.95    $1.16    $1.05    $1.02
Gal)
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    $0.95    $1.16    $1.05    $1.02
Gal)
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        $3.22    $2.98    $3.10    $3.85
excluding LTIP
Total general and administrative  $3.98    $3.54    $3.76    $4.44
Depletion, depreciation,          $22.02   $23.48   $22.75   $18.44
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; 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 MonthsEnded        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         39,113      41,652       80,765       48,209
accretion
Impairment of long-lived 20,774      1,743        22,517       15,279
assets
Gain on sale of assets   (46)        (219)        (265)        (3,324)
Equity in income of      (140)       (44)         (185)        (57)
equity method investees
Unit-based compensation  1,344       986          2,329        1,532
expense
Minimum payments earned
in excess of overriding  10          400          410          --
royalty interest ^(1)
EBITDA applicable to
equity method investee   226         --          226          --
^(2)
Unrealized (gains)
losses on oil and        (26,680)    15,640       (11,040)     (65,351)
natural gas derivatives
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 287         858          1,145        2,381
unit awards
Maintenance capital      17,000      17,000       34,000       
expenditures ^(3)
Total development                                             28,892
capital expenditures
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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