Legacy Reserves LP Announces Fourth Quarter 2012 Results, Annual 2012 Results and 2013 Guidance

Legacy Reserves LP Announces Fourth Quarter 2012 Results, Annual 2012 Results
and 2013 Guidance

MIDLAND, Texas, Feb. 25, 2013 (GLOBE NEWSWIRE) -- Legacy Reserves LP
("Legacy") (Nasdaq:LGCY) today announced annual and fourth quarter results for
2012 as well as financial guidance for 2013. Financial results contained
herein are preliminary and subject to the audited financial statements
included in Legacy's Form 10-K to be filed on or about February 27, 2013.

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

                      Three Months Ended              Twelve Months Ended
                      December 31,    September 30,   December 31,
                      2012            2012            2012        2011
                      (dollars in millions)
Production (Boe/d)     15,729         14,772         14,811     13,071
Revenue                $90.5           $84.2           $346.5      $336.9
Adjusted EBITDA (*)    $51.6           $49.5           $197.6      $201.4
Development capital    $19.7           $19.6           $68.2       $71.6
expenditures
Distributable Cash     $24.7           $23.7           $104.5      $107.8
Flow (*)
* 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.

2012 highlights include:

  *13% increase in production to 14,811 Boe/d from 13,071 Boe/d in 2011
    primarily due to (i) $635.4 million of acquisitions of producing
    properties during 2012, which only includes twelve days of production from
    our $502.6 million Permian Basin acquisition from Concho Resources Inc.
    ("2012 COG Acquisition"), (ii) a full-year impact of our 2011
    acquisitions, and (iii) $68.2 million of development capital expenditures
    during 2012.
    
  *31% increase in year-end proved reserves to 83.2 MMBoe (88% PDP, 68%
    liquids) compared to 63.4 MMBoe (85% PDP, 68% liquids) as of year-end 2011
    primarily driven by a 27.0 MMBoe increase from acquisitions partially
    offset by a 5.4 MMBoe decrease from production and a 2.4 MMBoe decrease
    from lower commodity prices.
    
  *Adjusted EBITDA of $197.6 million, the second highest in our history
    despite lower realized commodity prices and higher workover and other
    unusual well failure expenses.

Q4 2012 highlights include:

  *6% increase in production to 15,729 Boe/d from 14,772 Boe/d in the prior
    quarter primarily due to $519.8 million of acquisitions during the quarter
    including twelve days of production (approximately 640 Boe/d for the
    quarter) from our 2012 COG Acquisition, our development activity in the
    Wolfberry, and an outstanding horizontal Bone Spring well that began
    producing in November.
    
  *4% increase in Adjusted EBITDA to $51.6 million from $49.5 million during
    the third quarter.
    
  *Ninth consecutive increase in our quarterly distribution, ending the year
    at $0.57 per unit which represents 3.6% year-over-year growth.
    
  *To finance our recent acquisition and prepare for potential future
    acquisitions, (i) closed our largest equity offering in November providing
    $218.0 million in net proceeds, (ii) gained first-time access to the high
    yield market through our $300 million 8% senior notes offering, and (iii)
    increased our borrowing base for the third time in 2012 to $800 million
    with a newly-expanded 20-member bank group.

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy
Reserves GP, LLC, the general partner of Legacy, commented: "2012 was a
landmark year for Legacy, as we closed the largest acquisition in our history
on December 20, the $502.6 million acquisition of Permian Basin properties
from Concho. These properties are in some of the most prolific fields in the
Permian Basin. With the exception of the Lower Abo, these properties provide
us with a strong set of mature PDP assets with modest production decline rates
as well as a very strong portfolio of proved and unproved drilling locations
and developed, non-producing projects. Our integration of this acquisition is
going smoothly thus far, and since assuming operations on January 1, our
operations group is even more excited about the asset potential they are
seeing.

"The Concho acquisition helped us set a Company record in proved reserves with
83.2 MMBoe and, despite closing the transaction at the very end of the year,
we also set annual and quarterly production records of over 14,800 Boe/d
during 2012 and over 15,700 Boe/d during the fourth quarter. We generated
Adjusted EBITDA of $197.6 million, the second highest in our history, in the
face of challenging Midland-to-Cushing crude oil differentials and unusually
high well failure expenses. A market has developed to hedge the
Midland-to-Cushing differential and we have now hedged a significant portion
of our exposure during 2013. On the development front, we continue to be
pleased with our results from our Wolfberry drilling and are excited about the
results from our new horizontal Bone Spring well that began producing in
November. Due to our acquisitions, strong development results and promising
outlook, we increased our distribution every quarter during 2012, resulting in
year-over-year distribution growth of 3.6%. We have now increased our
distribution for the last nine consecutive quarters. For the year, assuming we
had used $50.0 million of our development capital expenditures as maintenance
capital expenditures (approximately 25% of our Adjusted EBITDA), our 2012
coverage ratio was 1.11 times. Using $13 million as maintenance capital
expenditures (roughly 25% of Adjusted EBITDA) and excluding the impact of the
Concho acquisition and our associated year-end capital raises, our fourth
quarter distributable cash flow per unit would have been approximately $0.64
per unit, covering our $0.57 distribution by 1.12 times.

"Due to our recent strong drilling results and our newly-expanded development
inventory, in January our board approved a 2013 capital budget of $90 million.
We consider $68 million of our budget to be maintenance capital. With our
multi-year, oil-weighted drilling inventory, our recently closed Concho
acquisition and our strong ongoing acquisition efforts, we are excited about
our opportunities in 2013 and beyond."

Dan Westcott, Executive Vice President and Chief Financial Officer, commented,
"We are very pleased with our acquisition efforts and growth in 2012. To
finance the Concho acquisition, we completed our largest equity offering and
issued $300 million of senior notes during the fourth quarter. In addition,
our now 20-member bank group redetermined our borrowing base at $800 million.
As of February 25, we had $500 million of debt outstanding under our revolving
credit facility, giving us approximately $300 of current availability (another
Company record) for future acquisitions and development projects. With
favorable conditions in the capital markets and ample availability under our
credit facility, we look forward to another year of strong results and the
pursuit of additional acquisitions."

2013 Guidance

The following table sets forth certain assumptions being used by Legacy to
estimate its anticipated results of operations for 2013. These estimates do
not include any acquisitions of additional oil or natural gas properties. In
addition, these estimates are based on, among other things, assumptions of
capital expenditure levels, current indications of supply and demand for oil
and natural gas and current operating and labor costs. The guidance set forth
below does not constitute any form of guarantee, assurance or promise that the
matters indicated will actually be achieved. The guidance below sets forth
management's best estimate based on current and anticipated market conditions
and other factors. While we believe that these estimates and assumptions are
reasonable, they are inherently uncertain and are subject to, among other
things, significant business, economic, regulatory, environmental and
competitive risks and uncertainties that could cause actual results to differ
materially from those we anticipate, as set forth under "Cautionary Statement
Relevant to Forward-Looking Information."

($ in thousands unless otherwise noted)  FY 2013E Range
Production:                                                    
Oil (MBbls)                              4,330          --       4,470
Natural gas liquids (MGal)               13,300         --       13,750
Natural gas (MMcf)                       14,050         --       14,500
Total (MBoe)                             6,988          --       7,214
Average daily production (Boe/d)         19,146         --       19,765
                                                              
Weighted Average NYMEX Differentials:                          
^(1)
Oil (per Bbl)                            ($7.50)        --       ($9.00)
NGL realization ^(2)                     1.00%          --       1.15%
Natural gas (per Mcf)                    $1.25          --       $1.35
                                                              
Expenses:                                                      
Oil and natural gas productionexpenses  $18.30         --       $19.20
($/Boe)
Ad valorem taxes (% of revenue)          3.25%          --       3.50%
Production and other taxes (% of         6.00%          --       6.50%
revenue)
Cash G&A expenses ^(3)                   $25,400        --       $26,650
                                                              
(1)Based on current NYMEX strip pricing. Excludes the impact of commodity
derivatives. Q1 2013 oil differentials are projected to be materially wider
($11.75--$13.50) primarily driven by recent Midland-to-Cushing differentials
which have since narrowed considerably.

(2)Represents the projected percentage of WTI crude oil prices divided by 42,
as we report NGLs in gallons.

(3)Consistent with our definition of Adjusted EBITDA, these figures exclude
LTIP expenses.Cash settlements of LTIP (not included herein) impact
Distributable Cash Flow.

Annual Financial and Operating Results – 2012 Compared to 2011

  *Production increased 13% to 14,811 Boe/d from 13,071 Boe/d primarily due
    to (i) $635.4 million of acquisitions of producing properties during 2012,
    which only includes twelve days of production from our 2012 COG
    Acquisition, (ii) a full-year impact of our $136.7 million of acquisitions
    of producing properties during 2011, and (iii) $68.2 million of
    development capital expenditures during 2012 which was the second highest
    annual total in our history and was primarily focused on our Wolfberry
    locations as well as major workovers in the Permian Basin and Wyoming. By
    commodity, our daily oil production increased by 13% in 2012 due to
    acquisitions and oil-focused development projects. Our daily natural gas
    production increased by 17% in 2012 due primarily to the full-year impact
    during 2012 of our 2011 acquisitions which were natural gas-weighted and,
    to a lesser extent, production from our 2012 acquisitions and development
    activities, as the Wolfberry play primarily produces oil but also a
    significant amount of casinghead natural gas, which is rich in natural gas
    liquids ("NGL"). Daily NGL production was flat (+0.1%) in 2012.
    
  *Average realized prices, excluding commodity derivatives settlements, were
    $63.91 per Boe in 2012, down 9% from $70.61 per Boe in 2011. Average
    realized oil prices decreased 4% to $85.78 per Bbl in 2012 from $89.62 per
    Bbl in 2011. This decrease of $3.84 per Bbl is primarily attributable to
    an increased weighted-average oil differential of $2.75 per Bbl as well as
    a slightly lower weighted-average West Texas Intermediate ("WTI") crude
    oil price. This increase in our oil differential was driven largely by the
    record increase in the Midland-to-Cushing/WTI differential, which averaged
    approximately $2.99 per Bbl in 2012 compared to $0.50 per Bbl in 2011. In
    addition, average realized natural gas prices decreased 28% to $4.38 per
    Mcf in 2012 from $6.05 per Mcf in 2011. Our average realized natural gas
    prices are favorably impacted by the NGL content in our Permian Basin
    natural gas. Our lower realized natural gas price reflects a lower
    weighted-average Henry Hub natural gas price, which decreased by
    approximately $1.24 per MMBtu in 2012, as well as a lower, positive
    differential in 2012 that reflects the lower average prices of the NGL
    content in our Permian Basin natural gas. Finally, our average realized
    NGL price decreased 23% to $1.00 per gallon in 2012 from $1.30 per gallon
    in 2011.
    
  *Production expenses, excluding ad valorem taxes, increased 18% to $103.4
    million in 2012 from $87.6 million in 2011. On an average cost per Boe
    basis, production expenses increased 4% to $19.08 per Boe in 2012 from
    $18.37 per Boe in 2011. Production expenses increased primarily because of
    (i) $5.1 million related to increases in workover and other unusual well
    failure expenses due to both increases in number of incidents as well as
    average cost per job, and (ii) production expenses from our acquisitions,
    including $0.8 million for the twelve days of activity related to the 2012
    COG Acquisition.
    
  *Legacy's general and administrative expenses excluding Long-Term
    Incentive Plan ("LTIP") compensation expense increased to $21.0 million
    from $19.1 million. The $1.9 million increase stems from a $3.3 million
    increase from salaries due to the hiring of additional personnel
    commensurate with the growth in our asset base, partially offset by lower
    acquisition-related costs of $1.3 million in 2012. Legacy's total general
    and administrative expenses were $24.5 million and $23.1 million for 2012
    and 2011, respectively. In addition to the factors above, Legacy's
    unit-based/LTIP compensation was $0.5 million lower in 2012 due to
    decreases in our unit price between December 31, 2011 and December 31,
    2012.
    
  *Cash settlements received on our commodity derivatives during 2012 were
    $5.9 million, as the $16.1 million received on our natural gas hedges was
    partially offset by $10.2 million paid on our oil hedges. This $5.9
    million in cash settlements received compared to $0.6 million received
    during 2011. Our production was 68% hedged in 2012 compared to 71% hedged
    in 2011.
    
  *Development capital expenditures decreased to $68.2 million in 2012 from
    $71.6 million in 2011, as we continued with our one-rig Wolfberry operated
    drilling program for most of 2012, drilled our first new horizontal Bone
    Spring well in late 2012, and increased our capital workover activity in
    the Permian Basin and Wyoming relative to 2011. Our non-operated capital
    expenditures were 23% of our total capital expenditures in 2012 as
    compared to 25% in 2011.

2012 Financial and Operating Results – Fourth Quarter Compared to Third
Quarter

  *Production increased by 6% to 15,729 Boe/d compared to 14,772 Boe/d in the
    prior quarter primarily due to recent acquisitions including twelve days
    of production (approximately 640 Boe/d for the quarter) from our 2012 COG
    Acquisition, our development in the Wolfberry, and an outstanding
    horizontal Bone Spring well that began producing in November. Production
    in the fourth quarter continued to be hampered by high pressures in
    natural gas gathering lines in the Permian Basin primarily due to
    extensive development in the area. In addition, natural gas and NGL
    production was down in the Texas Panhandle in the fourth quarter due to
    plant downtime.
    
  *Average realized prices, excluding commodity derivatives settlements, were
    $62.51 per Boe in the fourth quarter, up 1% from $61.95 per Boe in the
    third quarter. Average realized oil prices decreased by 3% to $80.69 per
    Bbl in the fourth quarter from $83.54 per Bbl in the third quarter. This
    decrease was attributable to a drop in average WTI crude oil prices, as an
    increase in the Midland-to-Cushing differential was offset by a
    significant decrease in our Rockies differentials during the fourth
    quarter. In addition, average realized natural gas prices increased 15% to
    $4.71 per Mcf in the fourth quarter from $4.10 per Mcf in the third
    quarter and average realized NGL prices increased 15% to $1.05 per gallon
    in the fourth quarter from $0.91 per gallon in the third quarter.
    
  *Production expenses, excluding taxes, remained flat at $28.3 million in
    the fourth quarter from $28.2 million in the third quarter, as production
    expenses associated with recent acquisitions, including $0.8 million
    associated with the twelve days of activity from the 2012 COG Acquisition,
    were offset by lower workover and other well failure related expenses,
    which were still roughly $1.0 million above normal levels but
    approximately $1.1 million lower than those expenses during the third
    quarter. Production expenses per Boe decreased 6% to $19.59 per Boe in the
    fourth quarter from $20.76 per Boe in the third quarter.
    
  *Legacy's general and administrative expenses excluding unit-based/LTIP
    compensation expense totaled $6.0 million during the fourth quarter
    compared to $4.9 million in the third quarter. This increase was
    attributable to acquisition-related and year-end compliance and other
    costs. Legacy's total general and administrative expenses were $5.9
    million during the fourth quarter compared to $7.0 million during the
    third quarter. LTIP expense decreased to a $0.1 million benefit in the
    fourth quarter compared to a $2.1 million expense in the third quarter
    primarily due to fluctuations in our unit price.
    
  *Cash settlements received on our commodity derivatives during the fourth
    quarter were $3.9 million compared to $6.1 million received during the
    third quarter. The decline in WTI crude oil prices between September and
    December resulted in a negative one-month lag effect on our crude oil
    hedges, with our cash settlements received being approximately $1.4
    million lower during the fourth quarter. In contrast, this lag effect
    caused our cash settlements received on our oil hedges to be approximately
    $2.7 million higher during the third quarter due to rising oil prices
    during that period.
    
  *Development capital expenditures were relatively flat at $19.7 million in
    the fourth quarter compared to $19.6 million in the third quarter, making
    it the second highest quarter for development capital expenditures in
    Legacy's history. Our development capital expenditures in the fourth
    quarter included our Wolfberry drilling program as well as an operated
    horizontal Bone Spring well that began producing in November. The results
    of our Wolfberry drilling program continue to meet or exceed expectations,
    and the results of our horizontal Bone Spring well have clearly exceeded
    expectations.

Commodity Derivatives Contracts

We have entered into the following oil and natural gas derivatives contracts,
including swaps and three-way collars, to help mitigate the risk of changing
commodity prices. As of February 25, 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 January 2013
through December 2017:

Crude Oil (WTI):

Calendar Year Volumes (Bbls) Average       Price
                             Price per Bbl Range per Bbl
2013          2,155,693     $90.92        $80.10 -- $108.65
2014          1,520,764     $91.54        $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:

Calendar Year Volumes (Bbls) Average Short Average Long Average Short
                             Put Price     Put Price    Call Price
2013          1,228,170     $65.53        $90.97       $105.85
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

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

Time Period  Volumes (Bbls) Average       Price
                            Price per Bbl Range per Bbl
Q1 2013      180,000       ($1.25)       ($1.25)
Q2 - Q4 2013 2,200,000     ($1.47)       $(1.25) -- $(1.75)

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

Calendar Year Volumes (MMBtu) Average         Price
                              Price per MMBtu Range per MMBtu
2013          9,240,654      $4.31           $3.18 -- $6.89
2014          7,431,254      $4.34           $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 and natural gas index prices.

Annual Report on Form 10-K

Our consolidated, audited financial statements and related footnotes will be
available in our annual 2012 Form 10-K which will be filed on or about
February 27, 2013.

Conference Call

As announced on January 22, 2013, Legacy will host an investor conference call
to discuss Legacy's results on Tuesday, February 26, 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 Saturday,
March 2, 2013, by dialing 855-859-2056 or 404-537-3406 and entering replay
code 92534708. 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 an independent oil and natural gas 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         Twelve Months Ended
                             December 31, September 30, December 31,
                             2012         2012          2012       2011
                             (In thousands, except per unit data)
Revenues:                                                        
Oil sales                     $74,157    $70,173     $286,254 $264,473
Natural gas liquids (NGL)     3,850       3,492        14,592    18,888
sales
Natural gas sales             12,448      10,531       45,614    53,524
Total revenues                90,455      84,196       346,460   336,885
                                                                
Expenses:                                                        
Oil and natural gas           30,929      30,728       112,951   96,914
production
Production and other taxes    5,737       5,137        20,778    20,329
General and administrative    5,922       6,993        24,526    23,084
Depletion, depreciation,      29,102      24,833       102,144   88,178
amortization and accretion
Impairment of long-lived      14,510      7,277        37,066    24,510
assets
(Gain) loss on disposal of    568         260          (2,496)   (625)
assets
Total expenses                86,768      75,228       294,969   252,390
                                                                
Operating income              3,687       8,968        51,491    84,495
                                                                
Other income (expense):                                          
Interest income               5           3            16        15
Interest expense              (6,003)     (5,285)      (20,260)  (18,566)
Equity in income of           23          30           111       138
partnership
Realized and unrealized net
gains (losses) on commodity   4,409       (27,177)     38,493    6,857
derivatives
Other                         (31)        (51)         (118)     152
Income (loss) before income   2,090       (23,512)     69,733    73,091
taxes
                                                                
Income tax expense            (218)       (54)         (1,096)   (1,030)
                                                                
Net income (loss)             $1,872     $(23,566)   $68,637  $72,061
Income (loss) per unit --                                        
basic and diluted             $0.04      $(0.49)     $1.40    $1.63
                                                                
Weighted average number of
units used in computing net               
income (loss) per unit --
Basic                         52,416      47,869       48,991    44,093
Diluted                       52,454      47,869       48,991    44,112

                                                                
                                                                
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(dollars in thousands)
                                                                
                                                    December 31,
                                                    2012         2011
ASSETS                                                           
Current assets:                                                  
Cash and cash equivalents                            $3,509     $3,151
Accounts receivable, net:                                        
Oil and natural gas                                  37,547      35,489
Joint interest owners                                27,851      10,299
Other                                                551         204
Fair value of derivatives                            15,158      7,117
Prepaid expenses and other current assets            3,294       3,525
Total current assets                                 87,910      59,785
                                                                
Oil and natural gas properties, at cost:                         
Proved oil and natural gas properties using the      2,078,961   1,389,326
successful efforts method of accounting
Unproved properties                                  65,968      20,063
Accumulated depletion, depreciation, amortization    (573,003)   (450,060)
and impairment
                                                    1,571,926   959,329
                                                                
Other property and equipment, net of accumulated
depreciation and amortization of $4,618 and $3,530,  2,646       3,310
respectively
Operating rights, net of amortization of $3,531 and  3,486       3,983
$3,034, respectively
Fair value of derivatives                            15,834      10,188
Other assets, net of amortization of $7,909 and      7,804       6,611
$6,337, respectively
Investment in equity method investee                 393         282
Total assets                                         $1,689,999 $1,043,488
                                                                
LIABILITIES AND UNITHOLDERS' EQUITY                              
Current liabilities:                                             
Accounts payable                                     $1,822     $3,286
Accrued oil and natural gas liabilities              50,162      45,351
Fair value of derivatives                            10,801      18,905
Asset retirement obligation                          29,501      20,262
Other                                                11,437      9,646
Total current liabilities                            103,723     97,450
                                                                
Long-term debt                                       775,838     337,000
Asset retirement obligation                          132,682     100,012
Fair value of derivatives                            5,590       18,897
Other long-term liabilities                          1,886       1,794
Total liabilities                                    1,019,719   555,153
                                                                
Commitments and contingencies                                    
Unitholders' equity:                                             
Limited partners' equity - 57,038,942 and 47,801,682 670,183     488,264
units issued and outstanding, respectively
General partner's equity (approximately 0.03% and    97          71
0.04%, respectively)
Total unitholders' equity                            670,280     488,335
Total liabilities and unitholders' equity            $1,689,999 $1,043,488

                                                               
                                                               
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
                                                               
                           Three Months Ended         Twelve Months Ended
                           December 31, September 30, December 31,
                           2012         2012          2012        2011
                           (In thousands, except per unit data)
Revenues:                                                       
Oil sales                   $74,157    $70,173     $286,254  $264,473
Natural gas liquids sales   3,850       3,492        14,592     18,888
Natural gas sales           12,448      10,531       45,614     53,524
Total revenues              $90,455    $84,196     $346,460  $336,885
                                                               
Expenses:                                                       
Oil and natural gas         $28,343    $28,207     $103,409  $87,626
production
Ad valorem taxes            $2,586     $2,521      $9,542    $9,288
Total oil and natural gas
production including ad     $30,929    $30,728     $112,951  $96,914
valorem taxes
Production and other taxes  $5,737     $5,137      $20,778   $20,329
General and administrative  $6,046     $4,855      $20,980   $19,063
excluding LTIP
LTIP expense (benefit)      $(124)     $2,138      $3,546    $4,021
Total general and           $5,922     $6,993      $24,526   $23,084
administrative
Depletion, depreciation,    $29,102    $24,833     $102,144  $88,178
amortization and accretion
                                                               
Realized commodity                                              
derivative settlements:
Realized gains (losses) on  $738       $2,108      $(10,211) $(11,335)
oil derivatives
Realized gains on natural   $3,146     $4,000      $16,113   $11,972
gas derivatives
                                                               
Production:                                                     
Oil (MBbls)                 919         840          3,337      2,951
Natural gas liquids (MGal)  3,670       3,821        14,607     14,559
Natural gas (MMcf)          2,643       2,571        10,417     8,842
Total (MBoe)                1,447       1,359        5,421      4,771
Average daily production    15,729      14,772       14,811     13,071
(Boe/d)
                                                               
Average sales price per unit (excluding                          
commodity derivatives):
Oil price (per Bbl)         $80.69     $83.54      $85.78    $89.62
Natural gas liquids price   $1.05      $0.91       $1.00     $1.30
(per Gal)
Natural gas price (per Mcf) $4.71      $4.10       $4.38     $6.05
Combined (per Boe)          $62.51     $61.95      $63.91    $70.61
                                                               
Average sales price per
unit (including realized                             
commodity derivative
gains/losses):
Oil price (per Bbl)         $81.50     $86.05      $82.72    $85.78
Natural gas liquids price   $1.05      $0.91       $1.00     $1.30
(per Gal)
Natural gas price (per Mcf) $5.90      $5.65       $5.93     $7.41
Combined (per Boe)          $65.20     $66.45      $65.00    $70.74
                                                               
NYMEX oil index prices per                                      
Bbl:
Beginning of Period         $92.19     $84.96      $98.83    $91.38
End of Period               $91.82     $92.19      $91.82    $98.83
                                                               
NYMEX gas index prices per                                      
Mcf:
Beginning of Period         $3.32      $2.82       $2.99     $4.41
End of Period               $3.35      $3.32       $3.35     $2.99
                                                               
Average unit costs per Boe:                                     
Oil and natural gas         $19.59     $20.76      $19.08    $18.37
production
Ad valorem taxes            $1.79      $1.86       $1.76     $1.95
Production and other taxes  $3.96      $3.78       $3.83     $4.26
General and administrative  $4.18      $3.57       $3.87     $4.00
excluding LTIP
Total general and           $4.09      $5.15       $4.52     $4.84
administrative
Depletion, depreciation,    $20.11     $18.27      $18.84    $18.48
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 partnership;
  *Unit-based compensation expense (benefit) related to LTIP unit awards
    accounted for under the equity or liability methods; 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
  *Development capital expenditures (*).

* Beginning in the first quarter of 2013, Legacy intends to deduct only
maintenance capital expenditures instead of total development capital
expenditures in the computation and presentation of Distributable Cash Flow,
which will result in the measure of Distributable Cash Flow not being
comparable from period to period.

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

                                                       
                             Three MonthsEnded        Twelve Months Ended
                             December 31, September 30, December 31,
                             2012         2012          2012       2011
                             (dollars in thousands)
Net income (loss)             $1,872     $(23,566)   $68,637  $72,061
Plus:                                                            
Interest expense             6,003       5,285        20,260    18,566
Income tax expense            218         54           1,096     1,030
Depletion, depreciation,      29,102      24,833       102,144   88,178
amortization and accretion
Impairment of long-lived      14,510      7,277        37,066    24,510
assets
(Gain) loss on sale of assets 568         260          (2,496)   (625)
Equity in income of           (23)        (30)         (111)     (138)
partnership
Unit-based compensation       (124)       2,138        3,546     4,021
expense (benefit)
Unrealized (gains) losses on
oil and natural gas           (525)       33,285       (32,591)  (6,220)
derivatives
Adjusted EBITDA               $51,601    $49,536     $197,551 $201,383
                                                                
Less:                                                            
Cash interest expense         6,991       5,283        21,387    19,044
Cash settlements of LTIP unit 184         990          3,555     2,916
awards
Development capital           19,693      19,565       68,150    71,589
expenditures
Distributable Cash Flow       $24,733    $23,698     $104,459 $107,834

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

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